RM958000.docx

                                                          70 FERC ¶ 61,357

                              UNITED STATES OF AMERICA
                        FEDERAL ENERGY REGULATORY COMMISSION
         Promoting Wholesale Competition    )    Docket No. RM95-8-000
         Through Open Access                )
         Non-discriminatory Transmission    )    
         Services by Public Utilities       )
                                            )
         Recovery of Stranded Costs by      )    Docket No. RM94-7-001
         Public Utilities and Transmitting  )
         Utilities                          )
                   NOTICE OF PROPOSED RULEMAKING AND SUPPLEMENTAL
                           NOTICE OF PROPOSED RULEMAKING
                                  (March 29, 1995)
                                 TABLE OF CONTENTS
         I.   INTRODUCTION............................................  3
         II.  PUBLIC REPORTING BURDEN................................. 11
         III. DISCUSSION.............................................. 13
              A.  Summary of Authority and Findings................... 13
              B.  Legal Authority..................................... 16
                   1.  Undue Discrimination/Anticompetitive Effects... 16
                   2.  Section 211 Services........................... 27
              C.  Background.......................................... 29
                   1.  Structure of the Electric Industry                  
                       at Enactment of Federal Power Act.............. 29
                   2.  Significant Changes in the Electric Industry... 30
                   3.  The Public Utility Regulatory Policies
                       Act and the Growth of Competition.............. 37
                   4.  The Energy Policy Act.......................... 45
                   5.  The Present Competitive Environment............ 47
         Docket Nos. RM95-8-000
           and RM94-7-001               -2-
                        a.  Use of Sections 211 and 212 to Obtain          
                            Transmission Access....................... 48
                        b.  Commission's Comparability Standard....... 51
                        c.  Lack of Market Power in New                    
                            Generation................................ 57
                        d.  Further Commission Action Addressing a More    
                            Competitive Electric Industry............. 58
              D.  Need for Reform..................................... 63
                   1.  Market Power................................... 65
                   2.  Discriminatory Access.......................... 67
                   3.  Analogies to the Natural Gas Industry.......... 82  

                   4.  Coordination Rates............................. 85
              E.  The Proposed Regulations............................ 87
                   1.  Non-discriminatory Open Access Tariff
                       Requirement.................................... 88
                   2.  Implementing Non-discriminatory Open Access:        
                       Functional Unbundling.......................... 94

                   3.  Real-time Information Networks.................102  

                   4.  Non-discriminatory Open Access Tariff
                       Provisions.....................................102
                   5.  Pro Forma Tariffs..............................130
                   6.  Broader Use of Section 211.....................130
                   7.  Status of Existing Contracts...................133
                   8.  Effect of Proposed Rule on Commission's Criteria    
                       for Market-based Rates.........................134
                   9.  Effect of Proposed Rule on Regional
                       Transmission Groups............................136
              F.  Stranded Costs and Other Transition Costs...........138
              G.  Transmission/Local Distribution.....................249
         Docket Nos. RM95-8-000
           and RM94-7-001               -3-
              H.  Implementation......................................286
         IV.  REGULATORY FLEXIBILITY ACT..............................303
         V.   ENVIRONMENTAL STATEMENT.................................303
         VI.  INFORMATION COLLECTION STATEMENT........................304
         VII. PUBLIC COMMENT PROCEDURES...............................305
              REGULATORY TEXT.........................................307
              APPENDICES
              A.  Electric Utility Average Revenue Per
                  Kilowatthour, by State................................A
              B.  Point-to-Point Tariff.................................B
              C.  Network Tariff........................................C
              D.  List of Commenters in Docket No. RM94-7-000...........D
         I.   INTRODUCTION
              The electric power industry is today an industry in
         transition.  In response to changes in the law, technology, and
         markets, competitive pressures are steadily building in the
         industry.  Once the primary domain of large, vertically
         integrated utilities providing power at regulated rates, the
         industry now includes companies selling "unbundled" power at
         rates set by competitive markets.  New generating facilities are
         being built at costs well below the average costs of some
         vertically integrated utilities.  In this environment, more
         competition will mean lower rates for wholesale customers and,
         ultimately, for consumers.
              The Commission's goal is to encourage lower electricity
         rates by structuring an orderly transition to competitive bulk
         Docket Nos. RM95-8-000
           and RM94-7-001               -4-
         power markets.  Development of such markets is certain.  The
         questions are when and how.  Experience has shown that
         competitive pressures cannot be contained for long without
         serious economic distortions.  Competition will, we are
         confident, result in lower rates.  But experience has also shown
         that a measured transition from regulated to competitive markets
         is absolutely essential.
              Moving to competitive generation markets will fundamentally
         change long-standing regulatory relationships.  Utilities have
         invested billions of dollars in order to meet their obligations.
         Those investments have been made under a "regulatory compact"
         whereby utilities -- and their shareholders -- expect to recover
         prudently incurred costs.  With the advent of competition, even
         prudent investments may become stranded.  Reliance on past
         contractual and regulatory practices must be recognized and past
         investments must be protected to assure an orderly, fair
         transition to competition.
              The focus of our proposal today is to facilitate competitive
         wholesale electric power markets.  The key to competitive bulk
         power markets is opening up transmission services.  Transmission
         is the vital link between sellers and buyers.  To achieve the
         benefits of robust, competitive bulk power markets, all wholesale
         buyers and sellers must have equal access to the transmission
         grid.  Otherwise, efficient trades cannot take place and
         ratepayers will bear unnecessary costs.  Thus, market power
         Docket Nos. RM95-8-000
           and RM94-7-001               -5-
         through control of transmission is the single greatest impediment
         to competition.  Unquestionably, this market power is still being
         used today, or can be used, discriminatorily to block
         competition.
              The Commission has an obligation to prevent unduly
         discriminatory practices in transmission access.  In current
         circumstances, the absence of tariffs offering open access, non-
         discriminatory transmission services by each public utility
         impedes the transition to competitive markets greatly enough to
         be unduly discriminatory under section 206 of the Federal Power
         Act (FPA).  Proceeding as we have in the past, case-by-case,
         would delay unreasonably the transition to competitive markets.
         A patchwork of transmission systems -- some open and some not --
         would also lead to unfair practices and inequitable burdens.
              At the same time, while fulfilling our duty under section
         206 of the FPA to cure undue discrimination, we see no need now
         to abrogate existing contractual relationships.  Rather, we
         propose to provide a transition to a competitive generation
         industry that allows for the recovery of legitimate, prudent and
         verifiable costs lawfully incurred to serve customers under the
         terms of existing contracts.  In the context of today's electric
         industry, the goals of increased competition and lower bulk power
         rates are best pursued through a structured transition rather
         than through abrogating all existing contracts.
         Docket Nos. RM95-8-000
           and RM94-7-001               -6-
              In short, at this crossroad for the industry, it is critical
         to take the regulatory steps now to facilitate the transition to
         competitive bulk power markets in an orderly manner.  The most
         important of these steps are to ensure non-discriminatory access
         to the transmission grid for all wholesale buyers and sellers of
         electric energy in interstate commerce, and to address the
         transition costs associated with open transmission access.  The
         Commission will take these steps in a manner consistent with
         maintaining the reliability of the interstate transmission grid.
              In this proceeding, the Commission pursuant to its authority
         under sections 205 and 206:
              °    proposes to require all public utilities owning or
                   controlling facilities used for transmitting electric
                   energy in interstate commerce to file open access
                   transmission tariffs;
              °    proposes to require the utilities to take transmission
                   service (including ancillary services) for their own
                   wholesale sales and purchases of electric energy under
                   the open access tariffs;
              °    issues a supplemental proposed rule to permit the
                   recovery of legitimate and verifiable stranded costs
                   associated with requiring open access tariffs; and
              °    proposes regulations to implement the filing of the
                   open access tariffs and the initial rates under these
                   tariffs.
              The open access tariffs -- to be offered to all sellers and
         buyers of electric energy sold at wholesale in interstate
         commerce -- must offer wholesale transmission services (network
         and point-to-point), including ancillary services, on a non-
         Docket Nos. RM95-8-000
           and RM94-7-001               -7-
         discriminatory basis to third parties. 1/  In addition, the
         public utility must price separately all wholesale generation and
         transmission services (including ancillary services) and take
         wholesale transmission service under its own tariff, i.e.,
         "functionally unbundle" its wholesale generation and transmission
         services.  The proposed rule does not mandate the corporate
         separation of generation, transmission, and distribution
         functions.
              The proposed rule proposes pro forma tariffs for network and
         point-to-point services, defines non-discriminatory open access
         to include access to ancillary services, and requires that
         tariffs include a reciprocity provision requiring any user or
         agent of the user of the tariff that owns and/or controls
         transmission facilities to provide non-discriminatory access to
         the tariff provider.   
              To assure that the open access tariffs promote competition
         and do not operate in an unduly discriminatory manner, the
         proposed rule would require public utilities to provide all
         actual or potential transmission users the same access to
         information as the public utility enjoys.  The Commission is
         proposing to develop industry-wide real-time information networks
         in a separate Notice of Technical Conference that is being issued

         1/   Throughout this NOPR this requirement will be referred to as
              the "non-discriminatory open access" requirement.
         Docket Nos. RM95-8-000
           and RM94-7-001               -8-
         concurrently with this proposed rule. 2/
              Not all transmitting utilities are public utilities subject
         to the Commission's jurisdiction under section 206 of the FPA.
         3/  The Commission cannot pursuant to section 206 require non-
         public utilities to file open access tariffs .  Therefore, the
         proposed rule would encourage the broad application of section
         211 as an additional means of achieving the goal in the Energy
         Policy Act of 1992 of promoting increased wholesale competition.
         Without broader application of section 211, wholesale bulk power
         market participants could be denied access to more competitive
         generation sources to the detriment of consumers.  
              We presently do not find it necessary to use our authority
         under section 206 of the FPA to reform public utilities' existing
         requirements contracts or any other contracts to eliminate undue

         2/   Notice of Technical Conference and Request for
              Comments, Docket No. RM95-9-000.
         3/   Section 206 of the FPA applies to public utilities, whereas
              section 211 applies to transmitting utilities.  A public
              utility is defined under section 201(e) of the FPA as "any
              person who owns or operates facilities subject to the
              jurisdiction of the Commission under this Part (other than
              facilities subject to such jurisdiction solely by reason of
              sections 210, 211, or 212)."  A transmitting utility is
              defined under section 3(23) of the FPA as "any electric
              utility, qualifying cogeneration facility, qualifying small
              power production facility, or Federal power marketing agency
              which owns or operates electric power transmission
              facilities which are used for the sale of electric energy at
              wholesale."  Not all transmitting utilities are public
              utilities.  For instance, a municipally-owned electric
              utility that owns transmission facilities that are used for
              the sale of electric energy at wholesale is a transmitting
              utility, but is not a public utility.
         Docket Nos. RM95-8-000
           and RM94-7-001               -9-
         discrimination or attain more competitive bulk power markets.
         However, we seek information about existing requirements
         contracts, including the remaining life and notice provision in
         each such contract, and whether it would be in the public
         interest to modify any existing contracts.
              The Commission believes that the open access requirement
         will eliminate the transmission market power of public utilities
         by ensuring that all participants in wholesale power markets will
         have non-discriminatory open access to the transmission systems
         of public utilities.  This market power has been the Commission's
         primary concern in recent years in analyzing requests for market-
         based generation rates.  We therefore seek comments on the effect
         of industry-wide non-discriminatory open access on the
         Commission's criteria for authorizing power sales at market-based
         rates.
              The Commission's market-rate criteria also have included
         other aspects of market power, such as generation dominance.  In
         particular, we note the Commission's recent KCP&L decision, in
         which we dropped the generation dominance standard for market-
         based sales from new capacity. 4/  This rule proposes to codify
         that decision, and seeks comment on whether the generation
         dominance standard should also be dropped for market-based sales
         from existing capacity.  

         4/   See Kansas City Power & Light Company, 67 FERC ¶ 61,183 at
              61,557 (1994) (KCP&L).
         Docket Nos. RM95-8-000
           and RM94-7-001               -10-
              In issuing this proposed rule, we are particularly concerned
         with its possible effect on stranded costs.  It is important to
         couple our open access rule with a rule ensuring recovery of all
         legitimate transition costs, consistent with the guidelines
         established herein.  Accordingly, we are making preliminary
         findings with respect to the Stranded Cost NOPR issued on June
         29, 1994, seeking additional comments, and consolidating the
         Stranded Cost NOPR 5/ with this proposed rule.
              Because of the benefits associated with the transition to a
         competitive regime, it is important to have the open access
         tariffs in place as soon as possible.  Thus, we propose a two-
         stage procedure to accomplish that goal.  In Stage One, we would
         place generic open access tariffs in effect simultaneously on a
         date certain for every public utility that owns and/or controls
         transmission facilities 6/ and would establish rates for each
         public utility based on the most current Form No. 1 data
         available.  In Stage Two, utilities would be free to propose
         changes to the rates, terms, and conditions in the generic
         tariffs and customers and others would be free to file complaints
         seeking changes in the rates, terms, and conditions.  However,
         Stage Two tariffs must contain at least the non-price tariff

         5/   See Recovery of Stranded Costs by Public Utilities and
              Transmitting Utilities, Notice of Proposed Rulemaking,
              59 FR 35274 (July 11, 1994), IV FERC Stats. & Regs.,
              Proposed Regulations ¶ 32,507 (Stranded Cost NOPR).
         6/   Because power pools raise complex issues, we seek
              comments on how to implement the NOPR for power pools.
         Docket Nos. RM95-8-000
           and RM94-7-001               -11-
         terms and conditions contained in the pro forma tariffs.   
              Comments of all interested persons should be filed pursuant
         to the procedures set out below.  
         II.  PUBLIC REPORTING BURDEN
              A.  Docket No. RM95-8-000
              The proposed rule specifies filing requirements to be
         followed by public utilities in making non-discriminatory open
         access tariff filings.  The information collection requirements
         of the proposed rule are attributable to FERC-516 "Electric Rate
         Filings."  The current total annual reporting burden for FERC-516
         is 784,488 hours.
              The proposed rule requires public utilities filing non-
         discriminatory open access tariffs to provide certain information
         to the Commission.  The public reporting burden for the
         information collection requirements contained in the proposed
         rule is estimated to average 300 hours per response.  This
         estimate includes time for reviewing the requirements of the
         Commission's regulations, searching existing data sources,
         gathering and maintaining the necessary data, completing and
         reviewing the collection of information, and filing the required
         information.
              There are approximately 328 public utilities, including
         marketers and wholesale generation entities.  The Commission
         estimates that approximately 137 of these utilities own or
         control facilities used for the transmission of electric energy
         Docket Nos. RM95-8-000
           and RM94-7-001               -12-
         in interstate commerce and will respond to the information
         collection.  The respondents would be all public utilities
         required to file non-discriminatory open access tariffs.  These
         are the public utilities that are also transmitting utilities and
         either file Form 715 or have it filed on their behalf.  The
         information will be provided with each filing by a respondent.
         Accordingly, the public reporting burden is estimated to be
         41,100 hours.
              Send comments regarding this burden estimate or any other
         aspect of the Commission's collection of information, including
         suggestions for reducing this burden, to the Federal Energy
         Regulatory Commission, 941 North Capitol Street, N.E.,
         Washington, DC 20426 [Attention: Michael Miller, Information
         Services Division, [phone]], and to the Office of
         Information and Regulatory Affairs of the Office of Management
         and Budget [Attention:  Desk Officer for Federal Energy
         Regulatory Commission [phone]].
              B.  Docket No. RM94-7-001
              The initially proposed rule would require public utilities
         seeking to recover stranded costs to provide certain information
         to the Commission.  The Commission estimated that the public
         reporting burden for the information collection requirements
         contained in the initially proposed rule would be 50 hours per
         response.  The Commission also estimated that there would be ten
         respondents to the information collection annually.
         Docket Nos. RM95-8-000
           and RM94-7-001               -13-
              Under the proposed rule contained in this supplemental
         notice of proposed rulemaking, the information that public
         utilities will be required to file is not substantially different
         from that required by the initially proposed rule.  The
         Commission also believes that the average filing burden and
         frequency of filing will be approximately the same as under the
         initially proposed rule.  Therefore, the Commission estimates
         that there will be no additional public filing burden associated
         with the proposed rule.
              Send comments regarding this burden estimate or any other
         aspect of the Commission's collection of information, including
         suggestions for reducing this burden, to the Federal Energy
         Regulatory Commission, 941 North Capitol Street, N.E.,
         Washington, DC 20426 [Attention:  Michael Miller, Information
         Services Division, [phone]], and to the Office of
         Information and Regulatory Affairs of the Office of Management
         and Budget [Attention:  Desk Officer for Federal Energy
         Regulatory Commission [phone]].
         III. DISCUSSION
              A.  Summary of Authority and Findings
              The primary purposes of the Federal Power Act are to curb
         abusive practices by public utility companies and to protect
         consumers from excessive rates and charges.  To achieve these
         ends, section 205 of the FPA requires that no public utility
         shall "make or grant any undue preference or advantage to any
         Docket Nos. RM95-8-000
           and RM94-7-001               -14-
         person or subject any person to any undue preference or
         disadvantage," with respect to the transmission of electric
         energy in interstate commerce or the sale for resale of electric
         energy in interstate commerce. 7/  Section 206 of the FPA
         authorizes the Commission to investigate and remedy unduly
         discriminatory or preferential rules, regulations, practices or
         contracts affecting public utility rates for transmission in
         interstate commerce or for sales for resale in interstate
         commerce.
              The significant technological, structural, statutory, and
         regulatory changes over the past twenty years have affected the
         electric utility industry such that competitive bulk power
         markets are now emerging.  This transition has expanded what the
         Commission must consider to be undue discrimination in the rates,
         terms, and conditions offered by public utilities.  We find that
         utilities owning or controlling transmission facilities possess
         substantial market power; that, as profit maximizing firms, they
         have and will continue to exercise that market power in order to
         maintain and increase market share, and will thus deny their
         wholesale customers access to competitively priced electric
         generation; and that these unduly discriminatory practices will
         deny consumers the substantial benefits of lower electricity
         prices.  We propose to prevent this discrimination by requiring
         all public utilities owning and/or controlling transmission

         7/   16 U.S.C. §§ 824d(b) and 824(d).
         Docket Nos. RM95-8-000
           and RM94-7-001               -15-
         facilities to offer non-discriminatory open access transmission
         services.
              At the same time, we see no need now to abrogate existing
         contractual relationships.  Instead, contracts should be
         permitted to run their course.  Additionally, we believe that
         recovery of legitimate stranded costs is critical to the
         successful transition of the electric utility industry from a
         tightly regulated, cost-of-service utility industry to an open
         access, competitively priced power industry.
              The requirement of open access coupled with the recovery of
         legitimate stranded costs furthers the Congressional purposes
         embodied in the Federal Power Act and the Energy Policy Act of
         1992 of protecting consumers, ensuring reasonable rates, and
         encouraging competition.
              Below, we set out the Commission's legal authority to
         require non-discriminatory open access, the relevant historical
         developments in the electric industry, and the need for
         regulatory reform. 8/

         8/   On February 16, 1995, the Coalition for a Competitive
              Electric Market filed a petition for a rulemaking on
              comparability.  The Industrial Consumers and the
              Transmission Access Policy Study Group filed comments in
              support of the petition.  The Commission will not separately
              notice the Coalition's petition, but seeks comment on that
              pleading, and the supporting pleadings, in this notice of
              proposed rulemaking.
         Docket Nos. RM95-8-000
           and RM94-7-001               -16-
              B.  Legal Authority
                   1.  Undue Discrimination/Anticompetitive Effects
              The Commission has authority to remedy undue discrimination.
         That is clear.  Some may argue that case law under the FPA limits
         our authority to order wheeling.  We have carefully analyzed
         relevant cases examining our wheeling authority.  We conclude
         that we have authority to require wheeling, or non-discriminatory
         open access, as a remedy for undue discrimination.  Our analysis
         of the case law is set forth below.
              In upholding the Commission's order requiring non-
         discriminatory open access in the natural gas industry, the court
         in Associated Gas Distributors v. FERC stated that the Natural
         Gas Act "fairly bristles" with concern for undue discrimination.
         9/  The same is true of the FPA.  The Commission has a mandate
         under sections 205 and 206 of the FPA to ensure that, with
         respect to any transmission in interstate commerce or any sale of
         electric energy for resale in interstate commerce by a public
         utility, no person is subject to any undue prejudice or
         disadvantage.  We must determine whether any rule, regulation,
         practice or contract affecting rates for such transmission or
         sale for resale is unduly discriminatory or preferential, and
         must prevent those contracts and practices that do not meet this
         standard.  As discussed below, AGD demonstrates that our remedial

         9/   Associated Gas Distributors v. FERC, 824 F.2d 981, 998
              (D.C.Cir. 1987), cert. denied, 485 U.S. 1006 (1988) (AGD).
         Docket Nos. RM95-8-000
           and RM94-7-001               -17-
         power is very broad and includes the ability to order industry-
         wide non-discriminatory open access as a remedy for undue
         discrimination.  Moreover, the Commission's power under the FPA
         "clearly carries with it the responsibility to consider, in
         appropriate circumstances, the anticompetitive effects of
         regulated aspects of interstate utility operations pursuant to
         [FPA] §§ 202 and 203, and under like directives contained in §§
         205, 206, and 207." 10/
              Based on the mandates of sections 205 and 206 of the FPA and
         the case law interpreting the Commission's authority over
         transmission in interstate commerce, we conclude that we have
         ample legal authority -- indeed, a responsibility -- under
         section 206 of the FPA to order the filing of non-discriminatory
         open access transmission tariffs if we find such order necessary
         as a remedy for undue discrimination or anticompetitive effects.
         11/  We discuss below the primary court decisions that touch
         on our wheeling authority under sections 205 and 206.
              The Commission's authority to order access as a remedy for

         10/  See Gulf States Utilities Company v. FPC, 411 U.S. 747, 758-
              59 (1973).
         11/  In most situations, discrimination that precludes
              transmission access or gives inferior access will have at
              least potential anticompetitive effects because it limits
              access to generation markets and thereby limits competition
              in generation.  Similarly, it is probable that any
              transmission provision that has anticompetitive effects
              would also be found to be unduly discriminatory or
              preferential because the anticompetitive provision would
              most likely favor the transmission owner vis-a-vis others.
         Docket Nos. RM95-8-000
           and RM94-7-001               -18-
         undue discrimination under the NGA was upheld and discussed in
         detail in AGD.  In AGD, the court upheld in relevant part the
         Commission's Order No. 436. 12/  That order found the
         prevailing natural gas company practices to be "unduly
         discriminatory" within the meaning of section 5 of the NGA (the
         parallel to section 206 of the FPA) and held that if pipelines
         wanted blanket certification for their transportation services,
         they must commit to transport gas for others on a non-
         discriminatory basis; in other words, they must provide non-
         discriminatory open access.  
              In upholding the Commission's authority to require open
         access, the court first noted that the opponents' arguments
         against such authority were "uphill."  The statute contains no
         language forbidding the Commission to impose common carrier
         status on pipelines, let alone forbidding the Commission to
         impose "a specific duty that happens to be a typical or even core
         component of such status."  The court found that the legislative
         history cited by the opponents came nowhere near overcoming this
         statutory silence.  Rather, the legislative history supported
         only the proposition that Congress itself declined to impose
         common carrier status. 13/  Emphasizing Congress' deep concern
         with undue discrimination, the court found that the Commission

         12/  Order No. 436, Regulation of Natural Gas Pipelines After
              Partial Wellhead Decontrol, III FERC Stats. & Regs.,
              Regulations Preambles ¶ 30,665 (1985).
         13/  AGD, supra, 824 F.2d at 997.
         Docket Nos. RM95-8-000
           and RM94-7-001               -19-
         had ample authority to "stamp out" such discrimination:   
                   The issue seems to come down to this:
                   Although Congress explicitly gave the
                   Commission the power and the duty to achieve
                   one of the prime goals of common carriage
                   regulation (the eradication of undue
                   discrimination), the Commission's attempted
                   exercise of that power is invalid because
                   Congress in 1906 and 1914 and 1935 and 1938
                   itself refrained from affixing common carrier
                   status directly onto the pipelines and from
                   authorizing the Commission to do so.  And
                   this proposition is said to control no matter
                   how sound the Order may be as a response to
                   the facts before the Commission.  We think
                   this turns statutory construction upside
                   down, letting the failure to grant a general
                   power prevail over the affirmative grant of a
                   specific one. [14/]

         The AGD court found that court decisions under the FPA did not
         support the view that the Commission's authority to "stamp out"
         undue discrimination is hamstrung by an inability to require non-
         discriminatory open access as a remedy.  These decisions are
         discussed below.  
              One of the earliest cases on wheeling is Otter Tail Power
         Company v. United States (Otter Tail) 15/  That case was a
         civil antitrust suit against an electric utility.  The Court
         rejected the argument that the District Court could not order
         wheeling because to do so would conflict with the Federal Power
         Commission's (FPC) purported wheeling authority. 16/  It

         14/  Id. at 998.
         15/  410 U.S. 366 (1974).
         16/  Id. at 375-76.
         Docket Nos. RM95-8-000
           and RM94-7-001               -20-
         pointed out that Congress had decided not to impose a common
         carrier obligation on the electric power industry and noted that
         the Commission was not at that time granted power to order
         wheeling.  The Otter Tail case, however, did not address whether
         the Commission can require transmission in fulfillment of its
         duty to remedy undue discrimination.
              Richmond Power & Light Company v. FERC (Richmond) 17/
         also did not involve requiring wheeling to remedy undue
         discrimination.  In that case, the FPC, in reaction to the 1973
         oil embargo, was attempting to reduce dependence on oil.  The FPC
         requested that utilities with excess capacity wheel power to the
         New England Power Pool (NEPOOL).  In response, several suppliers
         and transmission owners filed rate schedules with the FPC that
         provided for voluntary wheeling.  Richmond Power & Light Company
         (Richmond) objected to these filings, claiming that they were
         unreasonable because they did not guarantee transmission access.
         The FPC refused to compel the utilities to wheel Richmond's
         power, stating that it did not have the authority to order a
         public utility to act as a common carrier.
              The D.C. Circuit upheld the Commission.  It acknowledged
         that Richmond's argument was persuasive in some respects, but
         stated that any conditions the Commission might impose could not
         contravene the FPA.  The court examined the legislative history
         of the FPA and stated that "[i]f Congress had intended that

         17/  574 F.2d 610 (D.C. Cir. 1978).
         Docket Nos. RM95-8-000
           and RM94-7-001               -21-
         utilities could inadvertently bootstrap themselves into common-
         carrier status by filing rates for voluntary service, it would
         not have bothered to reject mandatory wheeling. . . ." 18/
              However, the D.C. Circuit in no way indicated that the
         Commission was foreclosed from ordering transmission as a remedy
         for undue discrimination.  Richmond also had argued that the
         alleged refusal of the American Electric Power Company (AEP) and
         its affiliate, Indiana & Michigan Electric Company (Indiana), to
         wheel Richmond's excess energy was unlawful discrimination
         because AEP and Indiana wheeled higher-priced electricity from
         other AEP affiliates.  The court acknowledged that Richmond's
         claim of unlawful discrimination was theoretically valid, but
         found that Richmond had failed to prove its case.  It noted that
         if Richmond had argued that the rates were unjustifiably
         discriminatory, or that Indiana's failure to use its transmission
         capability fully or to purchase less expensive electricity for
         wheeling resulted in unnecessarily high rates, a different case
         would be before the court. 19/  The case thus does not in any
         way limit the Commission's authority to remedy undue
         discrimination.
              In Central Iowa Power Cooperative v. FERC, 20/ the FPC

         18/  Id. at 620.
         19/  Id. at 623, nn.53 and 57.
         20/  606 F.2d 1156 (D.C. Cir. 1979).
         Docket Nos. RM95-8-000
           and RM94-7-001               -22-
         21/ reviewed the terms of the Mid-Continent Area Power Pool
         (MAPP) Agreement under its section 205 and 206 authority.  The
         agreement contained two membership limitations.  First, the
         agreement established two classes of membership, with one class
         being entitled to more privileges than the other.  Second, the
         agreement excluded non-generating distribution systems from pool
         services.  The FPC found the first limitation on membership --
         the two-class system -- to be unduly discriminatory and not
         reasonably related to MAPP's objectives.  The FPC conditioned
         approval of the agreement under section 206 on the removal of the
         unduly discriminatory provision.  The FPC found that the second
         limitation, the exclusion of non-generating distribution systems,
         was not anticompetitive and did not render the agreement
         inconsistent with the public interest.
              On appeal, the D.C. Circuit affirmed the FPC's decision.
         The court found that the FPC did have authority to order changes
         in the scope of the MAPP agreement, if the agreement was unjust,
         unreasonable, unduly discriminatory or preferential under section
         206 of the FPA.  The court stated:
                   The Commission had authority, . . . under
                   section 206 of the Act, . . . to order
                   changes in the limited scope of the
                   Agreement, including the addition of pool
                   services, if, in the absence of such
                   modifications, the Agreement presented "any

         21/  While Central Iowa was pending, certain of the functions of
              the FPC were transferred to the FERC under the DOE
              Organization Act.  Accordingly, the FERC was substituted for
              the FPC as the respondent in the case.
         Docket Nos. RM95-8-000
           and RM94-7-001               -23-
                   rule, regulation, practice or contract [that
                   was] unjust, unreasonable, unduly
                   discriminatory or preferential." [22/]
         However, the court agreed with the FPC's conclusion that the
         limited scope of MAPP was not unjust, unreasonable, or unduly
         discriminatory.  The court recognized that a pool was not invalid
         under section 206 merely because a more comprehensive arrangement
         was possible.
              The D.C. Circuit upheld the Commission's refusal to
         eliminate the second limitation on membership by ordering MAPP
         participants to wheel to non-generating electric systems. 23/
         However, neither the Commission nor the court was presented with
         the argument that wheeling was necessary as a remedy for undue
         discrimination.
              In Florida Power & Light Company v. FERC (Florida), 24/
         the Commission ordered Florida Power & Light Company (FP&L) to
         file a tariff setting forth FP&L's policy relating to the
         availability of transmission service. 25/  FP&L objected to

         22/  606 F.2d at 1168.  
         23/  Id. at 1169; see also Municipalities of Groton v. FERC, 587
              F.2d 1296 (D.C. Cir. 1978).
         24/  660 F.2d 668 (5th Cir. 1981), cert. denied sub nom. Fort
              Pierce Utilities Authority v. FERC, 459 U.S. 1156 (1983).
         25/  FP&L provided transmission service when four conditions were
              met:  (1) the specific potential seller and buyer were
              contractually identified; (2) the magnitude, time and
              duration of the transaction were specified prior to the
              commencement of the transmission; (3) it could be determined
              that the transmission capacity would be available for the
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001               -24-
         including such a policy statement in its tariff and argued that
         the filing of such a policy would convert FP&L into a common
         carrier by obligating it to offer service to all customers.
         26/  There was no finding that the action ordered was
         necessary to remedy undue discrimination.
              The Fifth Circuit Court of Appeals agreed with FP&L that the
         mandatory filing of the policy statement would require FP&L to
         provide transmission service beyond its voluntary commitment
         because such a requirement would change its duties and
         liabilities. 27/  The Commission order would impose common
         carrier status on FP&L, the court found. 28/  The court noted
         that the Commission did not rely on a finding of anticompetitive

         25/(...continued)
              term of the contract; and (4) the rate was sufficient to
              cover FP&L's costs.
         26/  All utilities requesting wheeling services, subject to
              availability, would be entitled to receive transmission
              service under the filed terms.  Any changes to a filed rate
              must be filed with the Commission.  This is the so-called
              "filed rate doctrine."  See Northwestern Public Service
              Company v. Montana-Dakota Utilities Company, 181 F.2d 19, 22
              (8th Cir. 1980), aff'd, 341 U.S. 246 (1951).
         27/  Under the filed rate doctrine, a refusal to wheel would be
              unduly discriminatory under section 206 of the FPA.  As the
              court acknowledged, a customer refused service could
              petition the Commission to find that FP&L's policy of
              availability was unduly discriminatory under section 206(a)
              of the FPA.  The court said that in the absence of a tariff
              on file, a utility refused wheeling services would be unable
              to claim discrimination under section 206(a) of the FPA.
              660 F.2d at 675 (expressing "serious doubts that such a
              petition would be successful in the absence of a tariff").
         28/  Id. at 676.
         Docket Nos. RM95-8-000
           and RM94-7-001               -25-
         behavior and therefore the court did not address the Commission's
         power to remedy antitrust violations. 29/  
              The AGD court explicitly rejected the claim that the above
         line of cases establishes that the Commission lacks authority to
         require non-discriminatory open access. 30/  Opponents of the
         Commission's order argued in AGD that Richmond and Florida,
         supra, stand for the proposition that the Commission cannot
         indirectly do what it allegedly cannot do directly, that is,
         impose common carriage.  The AGD court  rejected these arguments,
         stating that the petitioners read the electric cases far too
         broadly:
                   [n]either Richmond nor Florida comes anywhere
                   near stating that the Commission is barred
                   from imposing an open-access condition in all
                   circumstances. [31/]
         The court noted that the Florida case had expressly left open the
         question of whether the Commission would be entitled to use an
         open access condition as a remedy for anticompetitive conduct,
         and that in Richmond the D.C. Circuit had said little more than
         that unwillingness to transmit for all could not be automatically
         deemed undue discrimination.  The court also noted the Central

         29/  Id. at 678.
         30/  The AGD court did not address New York State Electric & Gas
              Corporation v. FERC, 638 F.2d 388 (2d Cir. 1980), cert.
              denied, 454 U.S. 821 (1981) (NYSEG), presumably because that
              case did not concern whether the Commission could order
              wheeling as a remedy for undue discrimination.
         31/  824 F.2d at 999.
         Docket Nos. RM95-8-000
           and RM94-7-001               -26-
         Iowa case, supra, in which it had upheld a Commission order that
         found a power pooling agreement discriminatory on its face
         because the agreement gave one class of membership privileged
         status over another.  The court stated that the Central Iowa case
         "upholds the power of the Commission to subject approval of a set
         of voluntary transactions to a condition that providers open up
         the class of permissible users." 32/  The court added that it
         refused to "turn statutory construction upside down" by letting
         Congress' failure to grant a general power of common carriage
         prevail over the affirmative grant of the specific power to
         eradicate undue discrimination. 33/  
              We conclude that AGD's analysis of undue discrimination
         under sections 4 and 5 of the Natural Gas Act is equally
         applicable to an undue discrimination analysis under sections 205
         and 206 of the FPA.  The Commission and courts have long
         recognized that the NGA was patterned after the FPA and that the
         two statutes should be interpreted in the same manner. 34/
         Thus, we conclude that we have the authority to remedy undue
         discrimination and anticompetitive effects by requiring all

         32/  Id. at 999.
         33/  Id. at 1006.
         34/  See, e.g., FPC v. Sierra Pacific Power Company, 350 U.S.
              348, 353 (1956); Arkansas Louisiana Gas Company v. Hall, 453
              U.S. 571, 577 n.7 (1981); and Kentucky Utilities Company v.
              FERC, 760 F.2d 1321, 1325 n.6 (D.C. Cir. 1985).  Section 206
              of the FPA was recently revised and now differs from section
              5 of the NGA, but not in a manner significant to our
              discussion here.  See 16 U.S.C. §§ 824e(b) and (c).
         Docket Nos. RM95-8-000
           and RM94-7-001               -27-
         public utilities that own and/or control transmission facilities
         to file non-discriminatory open access transmission tariffs.
                   2.  Section 211 Services
              In concluding that we must invoke our section 206 authority
         to remedy undue discrimination and anticompetitive actions in the
         electric industry, we have carefully considered the goals of
         Title VII of the Energy Policy Act, and whether section 211, by
         itself, is sufficient to remedy undue discrimination in public
         utility transmission services. 35/  Title VII of the Energy
         Policy Act, which amended section 211 of the FPA, reflects the
         intent of Congress to encourage competitive wholesale electric
         markets.  Section 211 provides a means for wholesale power
         sellers and buyers to obtain transmission services necessary to
         compete in, or to reach, competitive markets, and is a valuable
         tool to encourage competitive markets.  However, as discussed
         below, reliance on section 211 alone in some circumstances can
         result in the perpetuation of, rather than the elimination of,
         undue discrimination and anticompetitive effects.
              First, there are inherent delays in the procedures for
         obtaining service under section 211.  However, for competitive
         reasons, many transactions must be negotiated relatively quickly.
         Many competitive opportunities will be lost by the time the

         35/  In amending section 211 Congress left unaltered the
              authorities and obligations of the Commission under sections
              205 and 206 (similar to our authorities and obligations
              under sections 4 and 5 of the Natural Gas Act) to remedy
              undue discrimination.
         Docket Nos. RM95-8-000
           and RM94-7-001               -28-
         Commission can issue a final order under section 211.  While we
         interpret section 211 to permit a customer or group of customers
         to seek broad tariff-like arrangements, 36/ case-by-case
         section 211 proceedings are not a substitute for tariffs of
         general applicability that permit timely, non-discriminatory
         access on request.
              Second, discrimination is inherent in the current industry
         environment in which some customers and sellers are served by
         open access systems, and others have to rely on negotiated
         bilateral arrangements or the mandatory section 211 process.  The
         end result is discrimination in the ability to obtain
         transmission services, as well as in the quality and prices of
         the services.  This national patchwork of open and closed
         transmission systems cannot be cured effectively through section
         211.
              The Commission believes that its actions under sections 205
         and 206 will complement the section 211 procedures in achieving
         the goals of creating more competitive bulk power markets and
         lower rates for consumers, while avoiding many years of costly
         and unnecessary litigation.  Section 211 will be particularly
         important for developing non-discriminatory access by non-public
         utilities.

         36/  See El Paso Electric Company and Central and South West
              Services Inc., 68 FERC ¶ 61,181 at 61,916 (1994) (CSW),
              reh'g pending.
         Docket Nos. RM95-8-000
           and RM94-7-001               -29-
              C.  Background
                   1.  Structure of the Electric Industry
                       at Enactment of Federal Power Act
              The Federal Power Act was enacted in an age of mostly self-
         sufficient, vertically integrated electric utilities, in which
         generation, transmission, and distribution facilities were owned
         by a single entity and sold as part of a bundled service
         (delivered electric energy) to wholesale and retail customers.
         Most electric utilities built their own power plants and
         transmission systems, entered into interconnection and
         coordination arrangements with neighboring utilities, and entered
         into long-term contracts to make wholesale requirements sales
         (bundled sales of generation and transmission) to municipal,
         cooperative, and other investor-owned utilities (IOUs) connected
         to each utility's transmission system.  Each system covered
         limited service areas.  This structure of separate systems arose
         naturally due primarily to the cost and technological limitations
         on the distance over which electricity could be transmitted.  
              Through much of the 1960s, utilities were able to avoid
         price increases, but still achieve increased profits, because of
         substantial increases in scale economies, technological
         improvements, and only moderate increases in input prices. 37/

         37/  Paul L. Joskow, Inflation and Environmental Concern:
              Structural Change in the Process of Public Utility
              Regulation, 17 J. Law & Econ. 291, 312 (1974); see also
              Charles F. Phillips, Jr., The Regulation of Public Utilities
              11 (1988).
         Docket Nos. RM95-8-000
           and RM94-7-001               -30-
         Thus, there was no pressure on regulatory commissions to use
         regulation to affect the structure of the industry. 38/
                   2.  Significant Changes in the Electric Industry  
              In the late 1960s and throughout the 1970s, a number of
         significant events occurred in the electric industry that changed
         the perceptions of utilities and began a shift to a more
         competitive marketplace for wholesale power. 39/  This was the
         beginning of periods of rapid inflation, higher nominal interest
         rates, and higher electricity rates. 40/  During this time,
         consumers became concerned about higher electricity rates and
         questioned any price increases filed by utilities. 41/
              During this same time frame, the construction of nuclear and
         other capital-intensive baseload facilities -- actively
         encouraged by federal and some state governments -- contributed
         to the continuing cost increases and uncertainties in the

         38/  See Joskow, supra note 37, at 312; see also Phillips, supra
              note 37, at 12.
         39/  See Joskow, supra note 37, at 312; see also Phillips, supra
              note 37, at 12-13.
         40/  See Joskow, supra note 37, at 312-13; see also Phillips,
              supra note 37, at 13.  The Arab oil embargo resulted in
              significantly higher oil prices through the 1970s.  See
              Richard J. Pierce, Jr., The Regulatory Treatment of Mistakes
              in Retrospect: Canceled Plants and Excess Capacity, 132 U.
              Pa. L. Rev. 497, 501 (1984).
         41/  See Joskow, supra note 37, at 313; see also Phillips, supra
              note 37, at 13.
         Docket Nos. RM95-8-000
           and RM94-7-001               -31-
         industry. 42/  These investments were made based on the
         assumptions that there would be steady increases in the demand
         for electricity and continued large increases in the price of
         oil. 43/  However, due to conservation and economic downturns,
         the expected demand increases did not materialize.  Load growth
         virtually disappeared in some areas, and many utilities
         unexpectedly found themselves with excess capacity. 44/  In
         addition, by the 1980s, the oil cartel collapsed, with a
         resulting glut of low- priced oil. 45/  At the same time,
         inflation substantially increased the costs of these large
         baseload generating plants. 46/  Surging interest rates
         further increased the cost of the capital needed to finance and
         capitalize these projects and completion schedules were
         significantly extended by, in part, more stringent safety and

         42/  See generally Jersey Central Power & Light Company v. FERC,
              810 F.2d 1168, 1171 (D.C. Cir. 1987).
         43/  Id.
         44/  See Pierce, supra note 40, at 503.  By 1983, the Department
              of Energy had estimated that the sunk costs for canceled
              nuclear plants alone amounted to $10 billion.  Id. at 498.
         45/  Id.
         46/  See Bernard S. Black & Richard J. Pierce, Jr., The Choice
              Between Markets and Central Planning in Regulating the U.S.
              Electricity Industry, 93 Col. L. Rev. 1339, 1346 (1993)
              ("Actual costs of nuclear power plants vastly exceeded
              estimates, sometimes by as much as 1000%.").
         Docket Nos. RM95-8-000
           and RM94-7-001               -32-
         environmental requirements. 47/
              As a result, expensive large baseload plants came onto the
         market or were in the process of being constructed, for which
         there was little or no demand.  Accordingly, between 1970 and
         1985, average residential electricity prices more than tripled in
         nominal terms, and increased by 25% after adjusting for general
         inflation. 48/  Moreover, average electricity prices for
         industrial customers more than quadrupled in nominal terms over
         the same period and increased 86% after adjusting for inflation.
         49/  The rapidly increasing rates for electric power during
         this period, together with the opportunities provided by the
         Public Utility Regulatory Policies Act of 1978 (PURPA) (discussed
         infra), also prompted some industrial customers to bypass
         utilities by constructing their own generation facilities.  This

         47/  See Phillips, supra note 37, at 13.  Fossil fuel-fired
              plants became subject to increased regulation as a result of
              the Clean Air Act of 1970, and its 1977 amendments.  42
              U.S.C. § 7401-7642.  In 1971, nuclear plant licensing became
              subject to the environmental impact statement requirements
              of the National Environmental Policy Act of 1969.  42 U.S.C.
              § 4332.  Following the 1979 accident at the Three Mile
              Island nuclear plant, nuclear plants also became subject to
              additional safety regulations, resulting in higher costs.
              See Energy Information Administration, The Changing
              Structure of the Electric Power Industry 1970-1991 (March
              1993) 35.  Between 1976 and 1980, most states and many
              localities instituted laws governing power plant siting.
         48/  Based on retail prices reported in Energy Information
              Administration (EIA), Monthly Energy Review, January 1995,
              Table 9.9 (Prices adjusted for inflation using the GDP
              Deflator (1987 = 100)).
         49/  Id.
         Docket Nos. RM95-8-000
           and RM94-7-001               -33-
         further exacerbated rate increases for remaining customers --
         primarily residential and commercial customers.
              Consumers responded to these "rate shocks" by exerting
         pressure on regulatory bodies to investigate the prudence of
         management decisions to build generating plants, especially when
         construction resulted in cost overruns, excess capacity, or both.
         Between 1985 and 1992, writeoffs of nuclear power plants totalled
         $22.4 billion. 50/  These writeoffs significantly reduced the
         earnings of the affected utilities. 51/  Delays in obtaining
         rate increases to reflect the effects of inflation further
         reduced investor returns.  Thus, many utilities became reluctant
         to commit capital to long-term construction decisions involving
         large scale generating plants. 52/
              In addition to economic changes in the industry, significant
         technological changes in both generation and transmission have
         occurred since 1935.  Through the 1960s, bigger was cheaper in
         the generation sector and the industry was able to capitalize on
         economies of scale to produce power at lower per-unit costs from

         50/  See Black & Pierce, supra note 46, at 1346 (These writeoffs
              were "about 17% of the book value of total 1992 utility
              investment.").
         51/  Id.
         52/  Id. ("The high perceived risk of future disallowances
              reversed utilities' incentives to overinvest, and made
              utilities extremely reluctant to build new power plants.").
         Docket Nos. RM95-8-000
           and RM94-7-001               -34-
         larger and larger plants. 53/  As a result, large utility
         companies that could finance and manage construction projects of
         larger scale had a price advantage over smaller utility companies
         and customers who might otherwise have considered building their
         own generating units.  Scale economies encouraged power
         generation by large vertically-integrated utility companies that
         also transmitted and distributed power.  Beginning in the 1970s,
         however, additional economies of scale in generation were no
         longer being achieved. 54/  A significant factor was that
         larger generation units were found to need relatively greater
         maintenance and experience longer downtimes. 55/  The electric
         industry faced the situation "where the price of each incremental
         unit of electric power exceeded the average cost." 56/  Bigger
         was no longer better.  

         53/  See Preston Michie, Billing Credits for Conservation,
              Renewable, and Other Electric Power Resources:  an
              Alternative to Marginal-Cost-Based Power Rates in the
              Pacific Northwest, 13 Environmental Law 963, 964-65 (1983).
         54/  Id. at 965.
         55/  Energy Information Administration, The Changing Structure of
              the Electric Power Industry 1970-1991 (March 1993) 37 ("As
              larger units were constructed, however, utilities discovered
              that downtime was as much as 5 times greater for units
              larger than 600 megawatts than for units in the 100-megawatt
              range.")
         56/  Id.; see also George A. Perrault, Downsizing Generation:
              Utility Plans for the 1990s, Pub. Util. Fort. 15-16 (Sept.
              27, 1990) ("The large base-load generating units that form
              the backbone of utility systems are almost totally absent
              from capacity plans for the 1990s.").
         Docket Nos. RM95-8-000
           and RM94-7-001               -35-
              Further dictating against larger generation units were
         advances in technologies that allowed scale economies to be
         exploited by smaller size units, thereby allowing smaller new
         plants to be brought on line at costs below those of the large
         plants of the 1970s and earlier.  Such new technologies include
         combined cycle units and conventional steam units that use
         circulating fluidized bed boilers. 57/
              The combined cycle generating plants generally use natural
         gas as their primary fuel.  This technology has been made
         possible by the development of more efficient gas turbines,
         shorter construction lead times, lower capital costs, increased
         reliability, and relatively minimal environmental impacts. 58/
         Similarly, the circulating fluidized bed combustion boilers,
         fueled by coal and other conventional fuels, provide a more
         efficient and less polluting resource.
              Today, "the optimum size [of generation plants] has shifted
         from [more than 500 MW] (10-year lead time) to smaller units
         (one-year lead time) [in the 50- to 150-MW range]." 59/

         57/  "From 1982 through 1991, the average capacity of fluidized-
              bed units increased rapidly to 72 megawatts for 4 units in
              1991.  The average capacity for the 19 units planned to
              begin operating in 1992 through 1995 increases to 83
              megawatts."  Energy Information Administration, The Changing
              Structure of the Electric Power Industry 1970-1991 (March
              1993) 38.
         58/  See Charles E. Bayless, Less is More: Why Gas Turbines Will
              Transform Electric Utilities, Pub. Util. Fort. (Dec. 1,
              1994) 21.
         59/  Id. at 24.
         Docket Nos. RM95-8-000
           and RM94-7-001               -36-
         Indeed, smaller and more efficient gas-fired combined-cycle
         generation facilities can produce power on the grid at a cost
         between 3 and 5 cents per kWh. 60/  This is significantly less
         than the costs for large plants constructed and installed by
         utilities over the last decade, which were typically in the range
         of 4 to 7 cents per kWh for coal plants and 9 to 15 cents for
         nuclear plants. 61/   
              Significant changes have also occurred in the transmission
         sector of the industry.  Technological advances in transmission
         have made possible the economic transmission of electric power
         over long distances at higher voltages. 62/  This has made it
         technically feasible for utilities with lower cost generation
         sources to reach previously isolated systems where customers had
         been captive to higher cost generation.  In addition, the nature

         60/  FERC staff calculations based in part on combined-cycle
              plant cost data reported in 1993 FERC Form No. 1 for a
              sample of units placed in service during 1990-92.  Costs
              vary with regional fuel and construction costs, among other
              reasons.
         61/  Coal and Nuclear plant cost data reported in 1993 FERC Form
              No. 1 and the EIA report, Electric Plant Cost and Power
              Production Expenses 1991, 1993 DOE/EIA-0455(91), for plants
              placed in service during 1986-93; see also The 1994 Electric
              Executives' Forum, Bakke (President and CEO of the AES
              Corporation), Pub. Util. Fort. (June 1, 1994) 45 ("New
              generation can be built at about 3 cents per kilowatt-hour
              (U.S. average).  Old generation costs about twice
              that....").
         62/  See Black & Pierce, supra note 46, at 1345 (In the late
              1960s and 1970s, improved transmission efficiency and
              development of regional transmission networks "made it
              possible to build power plants up to 1000 miles from power
              users.").
         Docket Nos. RM95-8-000
           and RM94-7-001               -37-
         and magnitude of coordination transactions 63/ have changed
         dramatically since enactment of the FPA, allowing increased
         coordinated operations and reduced reserve margins.  Substantial
         amounts of electricity now move between regions, as well as
         between utilities in the same region.  Physically isolated
         systems have become a thing of the past.
                   3.  The Public Utility Regulatory Policies Act
                       and the Growth of Competition
              In enacting PURPA, 64/ Congress recognized that the
         rising costs and decreasing efficiencies of utility-owned
         generating facilities were increasing rates and harming the
         economy as a whole. 65/  To lessen dependence on expensive
         foreign oil, avoid repetition of the 1977 natural gas shortage,
         and control consumer costs, Congress sought to encourage electric
         utilities to conserve oil and natural gas. 66/  In particular,
         Congress sanctioned the development of alternative generation

         63/  Coordination transactions are voluntary sales or exchanges
              of specialized electricity services that allow buyers to
              realize cost savings or reliability gains that are not
              attainable if they rely solely on their own resources.  For
              sellers, these transactions provide opportunities to earn
              additional revenue, and to lower customer rates, from
              capacity that is temporarily excess to native load capacity
              requirements.
         64/  Pub. L. No. 95-617, 92 Stat. 3117 (codified in U.S.C.
              sections 15, 16, 26, 30, 42, and 43).  
         65/  See generally FERC v. Mississippi, 456 U.S. 742, 745-46
              (1982).
         66/  The Power Plant and Industrial Fuel Use Act of 1978.  Pub.
              L. No. 95-617, 92 Stat. 3117 (codified in U.S.C. sections
              15, 16, 26, 30, 42, and 43).    
         Docket Nos. RM95-8-000
           and RM94-7-001               -38-
         sources designated as "qualifying facilities" (QFs) as a means of
         reducing the demand for traditional fossil fuels. 67/  PURPA
         required utilities to purchase power from QFs at a price not to
         exceed the utility's avoided costs and to sell backup power to
         QFs. 68/    
              PURPA specifically set forth limitations on who, and what,
         could qualify as QFs.  In addition to technological and size
         criteria, PURPA set limits on who could own QFs. 69/
         Notwithstanding these limitations, QFs proliferated.  In 1989,
         there were 576 QF facilities.  By 1993, there were more than

         67/  QFs include certain cogenerators and small power producers.
              PURPA also added sections 210, 211 and 212 to the FPA,
              providing the Commission with authority to approve
              applications for interconnections and, in limited
              circumstances, wheeling.  However, under section 211, as
              enacted in PURPA, the Commission could approve an
              application for wheeling only if it found, inter alia, that
              the order "would reasonably preserve existing competitive
              relationships."  Because of this and other limitations in
              sections 211 and 212 as originally enacted, the provision
              was virtually ineffective.  Only one section 211 order was
              ever issued pursuant to the original provision, and it was
              pursuant to a settlement.  See Public Service Company of
              Oklahoma, 38 FERC ¶ 61,050 (1987).  As discussed infra,
              section 211 was subsequently revised by the Energy Policy
              Act of 1992.
         68/  456 U.S. at 750.  Congress recognized that encouragement was
              needed in part because utilities had been reluctant to
              purchase electric power from, and sell power to, nonutility
              generators.  Id. at 750-51.
         69/  For example, PURPA provided that a cogeneration facility or
              small power production facility could not be owned by a
              person primarily engaged in the generation or sale of
              electric power (other than from cogeneration or small power
              production facilities).  See 16 U.S.C. §§ 796(17) and (18).
         Docket Nos. RM95-8-000
           and RM94-7-001               -39-
         1,200 such facilities. 70/  For the same time period,
         installed QF capacity increased from 27,429 megawatts to 47,774
         megawatts. 71/  The rapid expansion and performance of the QF
         industry demonstrated that traditional, vertically integrated
         public utilities need not be the only sources of reliable power.
              During this period, the profile of generation investment
         began to change, and a market for non-traditional power supply
         beyond the purchases required by PURPA began to emerge.  QFs were
         limited to cogenerators and small power producers. 72/
         However, other non-traditional power producers who could not meet
         the QF criteria began to build new capacity to compete in bulk
         power markets, without such PURPA benefits as the mandatory
         purchase requirements.  These producers, known as independent

         70/  Energy Information Administration, Electric Power Annual
              1993 (December 1994) 124 (Table 77).
         71/  Id.  EIA data for 1989 through 1991 was for facilities of 5
              megawatts or more and for 1992 and 1993 was for facilities
              of 1 megawatt or more.  A comparison with Table 74 on page
              121 for the years 1992 and 1993 reveals that this mixing of
              data bases is likely of minimal effect.
         72/  Generally, the law has imposed an 80 MW cap on small power
              producers.  A limited exception enacted in 1990 permitted
              small power facilities that could exceed 80 MW and still
              qualify as QFs under PURPA.  This exception was limited to
              certain solar, wind, waste, and geothermal small power
              production facilities and only covered applications for
              certification of facilities as qualifying small power
              production facilities that were submitted no later than
              December 31, 1994 and for which construction commences no
              later than December 31, 1999.  See Solar, Wind, Waste, and
              Geothermal Power Production Incentives Act of 1990, Pub. L.
              No. 101-575, 104 Stat. 2834 (1990), amended, Pub. L. No.
              102-46, 105 Stat. 249 (1991).
         Docket Nos. RM95-8-000
           and RM94-7-001               -40-
         power producers (IPPs), were predominantly single-asset
         generation companies that did not own any transmission or
         distribution facilities.  While traditional utilities were
         generally reluctant at that time to invest in new generating
         facilities under cost of service regulation, utilities
         increasingly became interested in participating in this new
         generation sector.  They organized affiliated power producers
         (APPs), with assets not included in utility rate base, and sought
         to sell power in their own service territories and the
         territories of other utilities.  At the same time, power
         marketers arose.  These entities -- owning no transmission or
         generation -- buy and sell power. 73/
              There were two major impediments to the development of IPPs
         and APPs.  First, the ownership restrictions of the Public
         Utility Holding Company Act (PUHCA) 74/ severely inhibited
         these new entities from entering the generation business. 75/
         Second, these entities needed transmission service in order to
         compete in electricity markets.  

         73/  The first power marketer in the electric industry was
              Citizens Energy Corporation.  See Citizens Energy
              Corporation, 35 FERC ¶ 61,198 (1986).  Power marketers take
              title to electric energy.  Power brokers, on the other hand,
              do not take title and are limited to a matchmaking role.
         74/  15 U.S.C. §§ 79 et seq.
         75/  As discussed infra, Congress eventually provided a means to
              avoid the PUHCA restrictions by creating exempt wholesale
              generators (EWGs) in the Energy Policy Act.
         Docket Nos. RM95-8-000
           and RM94-7-001               -41-
              While the Commission had no authority to remove PUHCA
         restrictions, 76/ it encouraged the development of IPPs and
         APPs, as well as emerging power marketers, by authorizing market-
         based rates for their power sales on a case-by-case basis and by
         encouraging more widely available transmission access.  From 1989
         through 1993, facilities owned by IPPs and other non-traditional
         generators (other than QFs) increased from 249 to 634 and their
         installed capacity increased from 9,216 megawatts to 13,004
         megawatts. 77/  Indeed, "[i]n 1992, for the first time,
         generating capacity added by independent producers exceeded
         capacity added by utilities." 78/
              Market-based rates helped to develop competitive bulk power
         markets.  A generating utility allowed to sell its power at
         market-based rates could move more quickly to take advantage of
         short-term or even long-term market opportunities than those
         laboring under traditional cost-of-service tariffs, which entail
         procedural delays in achieving tariff approvals and changes.
              In approving these market-based rates, the Commission
         required, inter alia, that the seller and any of its affiliates
         lack market power or mitigate any market power that they may have

         76/  The industry was successful to some extent in developing
              ownership structures that permitted such investment.  See,
              e.g., Commonwealth Atlantic Limited Partnership, 51 FERC ¶
              61,368 at 62,240 and n.20 (1990).
         77/  Energy Information Administration, Electric Power Annual
              1993 (December 1994) 124 (Table 77).
         78/  Black & Pierce, supra note 46, at 1349 n.25.
         Docket Nos. RM95-8-000
           and RM94-7-001               -42-
         possessed. 79/  The major concern of the Commission was
         whether the seller or its affiliates could limit competition and
         thereby drive up prices.  A key inquiry became whether the seller
         or its affiliates owned or controlled transmission facilities in
         the relevant service area and therefore, by denying access or
         imposing discriminatory terms or conditions on transmission
         service, could foreclose other generators from competing. 80/
         As we have previously explained:
                   The most likely route to market power in
                   today's electric utility industry lies
                   through ownership or control of transmission
                   facilities.  Usually, the source of market
                   power is dominant or exclusive ownership of
                   the facilities.  However, market power also
                   may be gained without ownership.  Contracts
                   can confer the same rights of control.
                   Entities with contractual control over
                   transmission facilities can withhold supply
                   and extract monopoly prices just as
                   effectively as those who control facilities
                   through ownership. [81/]   

         79/  See, e.g., Ocean State Power, 44 FERC ¶ 61,261 (1988);
              Commonwealth Atlantic Limited Partnership, 51 FERC ¶ 61,368
              (1990); Citizens Power & Light Company, 48 FERC ¶ 61,210
              (1989); Orange and Rockland Utilities, Inc., 42 FERC ¶
              61,012 (1988); Doswell Limited Partnership, 50 FERC ¶ 61,251
              (1990) (Doswell); and Dartmouth Power Associates Limited
              Partnership, 53 FERC ¶ 61,117 (1990).
         80/  See, e.g., Doswell, 50 FERC at 61,757.
         81/  Citizens Power & Light Corporation, 48 FERC ¶ 61,210 at
              61,777 (1989) (emphasis in original); see also Utah Power &
              Light Company, PacifiCorp and PC/UP&L Merging Corporation,
              45 FERC ¶ 61,095 at 61,287-89 (1988), order on reh'g, 47
              FERC ¶ 61,209, order on reh'g, 48 FERC ¶ 61,035 (1989),
              remanded in part sub nom. Environmental Action, Inc. v.
              FERC, 939 F.2d 1057 (D.C. Cir. 1991), order on remand, 57
              FERC ¶ 61,363 (1991).
         Docket Nos. RM95-8-000
           and RM94-7-001               -43-
              As entry into wholesale power generation markets increased,
         the ability of customers to gain access to the transmission
         services necessary to reach competing suppliers became
         increasingly important. 82/  In addition, beginning in the
         late 1980s, public utilities seeking Commission approval of
         mergers or consolidations under section 203 of the FPA or
         Commission authorization for blanket approval of market-based
         rates for generation services under section 205 of the FPA, filed
         "open access" transmission tariffs of general applicability to
         mitigate their market power to meet Commission conditions. 83/

         82/  In earlier years, a few customers were able to obtain access
              as a result of litigation, beginning with the Supreme
              Court's decision in Otter Tail, 410 U.S. 366 (1973).
              Additionally, some customers gained access by virtue of
              Nuclear Regulatory Commission license conditions and
              voluntary preference power transmission arrangements
              associated with federal power marketing agencies.  See,
              e.g., Consumers Power Company, 6 NRC 887, 1036-44 (1977) and
              The Toledo Edison Company and Cleveland Electric
              Illuminating Company, 10 NRC 265, 327-34 (1979).  See
              Florida Municipal Power Agency v. Florida Power and Light
              Company, 839 F. Supp. 1563 (M.D. Fla. 1993).  See also
              Electricity Transmission:  Realities, Theory and Policy
              Alternatives, The Transmission Task Force Report to the
              Commission, October 1989, 197.  
         83/  See, e.g., Public Service Company of Colorado, 59 FERC ¶
              61,311 (1992), reh'g denied, 62 FERC ¶ 61,013 (1993); Utah
              Power & Light Company, et al., Opinion No. 318, 45 FERC ¶
              61,095 (1988), order on reh'g, Opinion No. 318-A, 47 FERC ¶
              61,209 (1989), order on reh'g, Opinion No. 318-B, 48 FERC ¶
              61,035 (1989), aff'd in relevant part sub nom. Environmental
              Action Inc. v. FERC, 939 F.2d 1057 (D.C. Cir. 1991);
              Northeast Utilities Service Company (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 relevant
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001               -44-
         The Commission applied its market rate analysis to IOUs, as well
         as IPPs, APPs, and marketers, and allowed IOUs to sell at market-
         based rates only if they opened their transmission systems to
         competitors. 84/  The Commission also approved proposed
         mergers on the condition that the merging companies remedy
         anticompetitive effects potentially caused by the merger by
         filing "open access" tariffs.  These early "open access" tariffs
         required only that the companies provide point-to-point
         transmission services, which is a much narrower requirement than
         that being proposed in this rule.  However, only 21 public
         utilities have any form of open access transmission; the vast
         majority of IOUs still do not provide any form of "open access"
         transmission over their transmission systems.
              The economic and technological changes in the transmission
         and generation sectors helped give impetus to the many new
         entrants in the generating markets who could sell electric energy
         profitably with smaller scale technology at a lower price than
         many utilities selling from their existing generation facilities
         at rates reflecting cost.  However, the advantages of these
         technological advances can be achieved only if  more efficient

         83/(...continued)
              part sub nom. Northeast Utilities Service Company v. FERC,
              993 F.2d 937 (1st Cir. 1993).
         84/  See, e.g., Public Service of Indiana, Inc., 51 FERC ¶ 61,367
              (1990), reh'g denied, 52 FERC ¶ 61,260 (1990), appeal
              dismissed sub nom. Northern Indiana Public Service Company
              v. FERC, 954 F.2d 736 (D.C.Cir. 1992).
         Docket Nos. RM95-8-000
           and RM94-7-001               -45-
         generating plants can obtain access to the regional transmission
         grids.  Because the traditional vertically integrated utilities
         still favor their own generation if and when they provide
         transmission access to third parties, barriers continue to exist
         to cheaper, more efficient generation sources.
                   4.  The Energy Policy Act
              In response to the competitive developments following PURPA,
         and the fact that PUHCA and lack of transmission access 85/
         remained major barriers to new generators, Congress enacted Title
         VII of the Energy Policy Act of 1992 (Energy Policy Act). 86/
         A goal of the Energy Policy Act was to promote greater
         competition in bulk power markets by encouraging new generation
         entrants, known as exempt wholesale generators (EWGs), and by
         expanding the Commission's authority under sections 211 and 212
         of the FPA to approve applications for transmission services.
         87/  
              An EWG is defined as
                   any person determined by the Federal Energy
                   Regulatory Commission to be engaged directly,
                   or indirectly through one or more affiliates

         85/  See infra sections III.D.1 and 2.
         86/  Pub. L. No. 102-486, 106 Stat. 2776 (1992).
         87/  See El Paso Electric Company and Central and South West
              Services Inc., 68 FERC ¶ 61,181 at 61,914 (1994); see also
              Paul Kemezis, FERC's Competitive Muscle: The Comparability
              Standard, Electrical World 45 (Jan. 1995) ("In EPAct,
              Congress made it clear that the electric-power industry was
              to move toward a fully competitive market system, but left
              most of the implementation to FERC.").
         Docket Nos. RM95-8-000
           and RM94-7-001               -46-
                   as defined in [PUHCA] section 2(a)(11)(B),
                   and exclusively in the business of owning or
                   operating, or both owning and operating, all
                   or part of one or more eligible facilities
                   and selling electric energy at wholesale.
                   [88/]
         If the Commission, upon an application, determines that a person
         is an EWG, that person will be exempt from PUHCA. 89/  This
         provision removed a significant impediment to the development of
         IPPs and APPs by allowing them to develop projects as EWGs free
         from the strictures of PUHCA or the QF PURPA limitations.
              While sections 211 and 212, as enacted by PURPA, were
         intended to provide greater access to the transmission grid, the
         limitations placed on these sections made them unusable in most
         circumstances. 90/  However, as amended by the Energy Policy
         Act, these sections now give the Commission broader authority to
         order transmitting utilities to provide wholesale transmission
         services, upon application, to any electric utility, Federal
         power marketing agency, or any other person generating electric
         energy for sale for resale.
              The Energy Policy Act also added section 213 to the FPA.
         Section 213(a) requires a transmitting utility that does not
         agree to provide wholesale transmission service in accordance
         with a good faith request to provide a written explanation of its

         88/  15 U.S.C. § 79z-5a.
         89/  15 U.S.C. § 79z-5a(e).
         90/  See supra note 67.
         Docket Nos. RM95-8-000
           and RM94-7-001               -47-
         proposed rates, terms, and conditions and its analysis of any
         physical or other constraints. 91/  Section 213(b) required
         the Commission to enact a rule requiring transmitting utilities
         to submit annual information concerning potentially available
         transmission capacity and known constraints. 92/   
                   5.  The Present Competitive Environment
              Following the Energy Policy Act, the Commission established
         rules:  (1) for certain generators to obtain EWG status and thus
         an exemption from PUHCA; 93/ and (2) that required
         transmission information availability.  The Commission also

         91/  See Policy Statement Regarding Good Faith Requests for
              Transmission Services and Responses by Transmitting
              Utilities Under Sections 211(a) and 213(a) of the Federal
              Power Act, as Amended and Added by the Energy Policy Act of
              1992, 58 FR 38964 (July 21, 1993), III FERC Stats. & Regs.,
              Regulations Preambles ¶ 30,975 (1993) (Policy Statement
              Regarding Good Faith Requests for Transmission Services).
         92/  See Order No. 558, New Reporting Requirements Implementing
              Section 213(b) of the Federal Power Act and Supporting
              Expanded Regulatory Responsibilities Under the Energy Policy
              Act of 1992, and Conforming and Other Changes to Form No.
              FERC-714, III FERC Stats. & Regs., Regulations Preambles ¶
              30,980, reh'g denied, Order No. 558-A, 65 FERC ¶ 61,324
              (1993), regulations modified, 59 FR 15333 (April 1, 1994),
              III FERC Stats. & Regs., Regulations Preambles ¶ 30,993.
         93/  See Order No. 550, Filing Requirements and Ministerial
              Procedures for Persons Seeking Exempt Wholesale Generator
              Status, 58 FR 8897 (February 18, 1993), III FERC Stats. &
              Regs., Regulations Preambles ¶ 30,964, order on reh'g, Order
              No. 550-A, 58 FR 21250 (April 20, 1993), III FERC Stats. &
              Regs., Regulations Preambles ¶ 30,969 (1993).  As recognized
              by Congress and the Commission, availability of transmission
              information is critical in developing competitive markets.
              See supra notes 91 and 92.  This opened the "black box" of
              information that previously was available only to
              transmission owners.
         Docket Nos. RM95-8-000
           and RM94-7-001               -48-
         pursued a number of initiatives aimed at fostering the
         development of more competitive bulk power markets, including
         aggressive implementation of section 211, a new look at undue
         discrimination under the FPA, easing of market entry for sellers
         of generation from new facilities, and initiation of a number of
         industry-wide reforms.  As stated by the Commission, in
         recognition of the Congressional goal in the Energy Policy Act of
         creating competitive bulk power markets:
                   Our goal is to facilitate the development of
                   competitively priced generation supply
                   options, and to ensure that wholesale
                   purchasers of electric energy can reach
                   alternative power suppliers and vice versa.
                   [94/]
                   a.  Use of Sections 211 and 212 to Obtain Transmission  
                       Access

               The Commission has aggressively implemented sections 211
         and 212 of the FPA, as amended by the Energy Policy Act, in order
         to promote competitive markets. 95/  When wheeling requests
         under sections 211 and 212 have been made, the Commission has
         required wheeling in almost all of the requests it has processed.
         To date, the Commission has issued orders requiring wheeling in 9
         of the 10 cases it has acted on, including 3 proposed orders and

         94/  See Stranded Cost NOPR at 32,866; American Electric Power
              Service Corporation, 67 FERC ¶ 61,168, clarified, 67 FERC ¶
              61,317 (1994).
         95/  16 U.S.C.A. §§ 824j-824k (West 1985 and Supp. 1994).
         Docket Nos. RM95-8-000
           and RM94-7-001               -49-
         6 final orders. 96/
              As a general matter, section 211 has permitted some inroads
         to be made by customers in obtaining transmission service from
         public utilities that historically have declined to provide
         access to their systems, or have offered service only on a
         discriminatory basis.  Under section 211, the Commission has
         granted requests for the broader type of service that most
         utilities historically have refused to provide -- network
         service.  Although transmission owners have provided limited
         amounts of unbundled point-to-point transmission service, third-
         party customers have not been able to obtain the flexibility of
         service that transmission owners enjoy.  
              In Florida Municipal, a section 211 case, the Commission
         ordered "network," rather than the narrower "point-to-point,"
         service. 97/  Network service permits the applicant to fully

         96/  See, e.g., final orders issued in City of Bedford, 68 FERC ¶
              61,003 (1994), reh'g pending; Florida Municipal Power Agency
              v. Florida Power & Light Company, 67 FERC ¶ 61,167 (1994),
              reh'g pending; Minnesota Municipal Power Agency, 68 FERC ¶
              61,060 (1994); and Tex-La Electric Cooperative of Texas, 69
              FERC ¶ 61,269 (1994); see also supra note 168.
         97/  See Florida Municipal Power Agency v. Florida Power & Light
              Company, 65 FERC ¶ 61,125, reh'g dismissed, 65 FERC ¶ 61,372
              (1993), final order, 67 FERC ¶ 61,167 (1994), reh'g pending.
              The Commission has "characterized point-to-point service as
              involving designated points of entry into and exit from the
              transmitting utility's system, with a designated amount of
              transfer capability at each point."  El Paso Electric
              Company v. Southwestern Public Service Company, 68 FERC ¶
              61,182 at 61,926 n.9 (1994) (citing Entergy Services, Inc.,
              58 FERC ¶ 61,234 at 61,768 (1993), reh'g dismissed, 68 FERC
              ¶ 61,399 (1994)).  Network service allows more flexibility
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001               -50-
         integrate load and resources on an instantaneous basis in a
         manner similar to the transmission owner's integration of its own
         load and resources.  At the same time, the Commission made the
         generic finding that the availability of transmission service
         will enhance competition in the market for power supplies and
         lead to lower costs for consumers.  The Commission explained that
         as long as the transmitting utility is fully and fairly
         compensated and there is no unreasonable impairment of
         reliability, transmission service is in the public interest.
         98/  
              As discussed in more detail above, however, our preliminary
         conclusion is that section 211 alone is not enough to eliminate
         undue discrimination.  The significant time delays involved in
         filing an individual service request for bilateral service under
         section 211 places the customer at a severe disadvantage compared
         to the transmission owner and can result in discriminatory
         treatment in the use of the transmission system.  It is an
         inadequate procedural substitute for readily available service
         under a filed non-discriminatory open access tariff.  As the
         Commission noted in Hermiston Generating Company, "[t]he ability
         to spend time and resources litigating the rates, terms and

         97/(...continued)
              by allowing a transmission customer to use the entire
              transmission network to provide generation service for
              specified resources and specified loads without having to
              pay multiple charges for each resource-load pairing.
         98/  Florida Municipal, 67 FERC at 61,477.   
         Docket Nos. RM95-8-000
           and RM94-7-001               -51-
         conditions of transmission access is not equivalent to an
         enforceable voluntary offer to provide comparable service under
         known rates, terms and conditions." 99/
                   b.  Commission's Comparability Standard
              In the Spring of 1994, the Commission began to address the
         problem of the disparity in transmission service that utilities
         provided to third parties in comparison to their own uses of the
         transmission system.  In the seminal case in this area, American
         Electric Power Service Corporation (AEP), the company voluntarily
         proposed a tariff of general applicability that would offer firm,
         point-to-point transmission service for a minimum of one month.
         100/  The Commission accepted the proposed transmission
         tariff for filing and suspended its effectiveness for one day,
         subject to refund. 101/  Rehearing requests challenged the
         Commission's summary approval of the restriction of service to
         point-to-point as being discriminatory and anticompetitive.
         102/  The rehearing requests argued that the tariff should be
         expanded to include network services such as those used by the

         99/  69 FERC ¶ 61,035 at 61,165 (1994), reh'g pending; see also
              Southwest Regional Transmission Association, 69 FERC ¶
              61,100 at 61,398 (1994) (SWRTA).
         100/ 64 FERC ¶ 61,279 (1993), reh'g granted, 67 FERC ¶ 61,168,
              clarified, 67 FERC ¶ 61,317 (1994).
         101/ The Commission explained that AEP could limit the service it
              was offering because it was "providing the service
              voluntarily under a tariff of general applicability." 64
              FERC at 62,978.
         102/ AEP, 67 FERC at 61,489.
         Docket Nos. RM95-8-000
           and RM94-7-001               -52-
         transmission owner.  On rehearing, the Commission announced a new
         standard for evaluating claims of undue discrimination.
              The Commission found that a voluntarily offered, new open
         access transmission tariff that did not provide for services
         comparable to those that the transmission owner provided itself
         was unduly discriminatory and anticompetitive. 103/  In
         reaching that conclusion, the Commission broadened its undue
         discrimination analysis (which traditionally had focused on the
         rates, terms, and conditions faced by similarly situated third-
         party customers) to include a focus on the rates, terms, and
         conditions of a utility's own uses of the transmission system:  
                   [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.
                   [104/]

         103/ With respect to anticompetitive effects, the Commission
              explained that it has "adhered to the Supreme Court's
              determination that the Commission's 'important and broad
              regulatory power . . . carries with it the responsibility to
              consider, in appropriate circumstances, the anticompetitive
              effects of regulated aspects of interstate utility
              operations pursuant to §§ 202 and 203, and under like
              directives contained in §§ 205, 206 and 207.'  Gulf States
              Utilities Company v. FPC, 411 U.S. 747, 758-59 (1972)."  Id.
              at 61,490 (footnote omitted).  The Commission reaffirmed
              that it would examine how best to fulfill this
              responsibility, as well as its responsibility to prevent
              undue discrimination, in light of the changing conditions in
              the electric utility industry.  Id.
         104/ Id. at 61,490.
         Docket Nos. RM95-8-000
           and RM94-7-001               -53-
         Refocusing the analysis was necessitated by the changing
         conditions in the electric utility industry, including the
         emergence of non-traditional suppliers and greater competition in
         bulk power markets.  Because a transmission provider may use its
         system in different ways (e.g., to integrate load and resources
         when serving retail native load, to make off-system sales or
         purchases, or to serve wholesale requirements customers), the
         Commission set for hearing the factual issues associated with
         identifying those uses, as well as any potential impediments or
         consequences to providing comparable services to third parties.
         105/
              After AEP, the Commission applied this comparability
         standard to a proposed open access transmission tariff that was
         filed by Kansas City Power & Light Company in support of a
         proposal to sell generation at market-based rates. 106/  The
         Commission explained that, in light of AEP, the utility's
         proposed open access transmission tariff (which provided only for
         point-to-point service) did not adequately mitigate its
         transmission market power so as to justify allowing the requested
         market-based rates.  KCP&L could charge market-based rates for
         sales only if it modified its proposed transmission tariff to
         reflect the AEP comparability standard.

         105/ Id. at 61,490-91.
         106/ See Kansas City Power & Light Company, 67 FERC ¶ 61,183
              (1994), reh'g pending.
         Docket Nos. RM95-8-000
           and RM94-7-001               -54-
              Since then, the Commission has required comparable service
         in a variety of contexts, and has set for hearing the factual
         issues associated with comparable service.  For example, the
         Commission found that market power can be adequately mitigated
         only if a merged company offers transmission services in
         accordance with the AEP comparability standard. 107/  The
         Commission further held that, even if a merger does not result in
         an increase in market power, the merger would not be consistent
         with the public interest under section 203 of the FPA unless the
         merged company offers comparable transmission services, as
         defined in AEP. 108/  The Commission therefore announced a
         transmission comparability requirement for all new mergers:
                   Given the transition of the electric utility
                   industry as a whole, we conclude that, absent
                   other compelling public interest considerations,
                   coordination in the public interest can best be
                   secured only if merging utilities offer comparable
                   transmission services. [109/]
              In Heartland Energy Services, Inc., 110/ the Commission
         applied its comparability standard to an affiliated electric
         power marketer seeking blanket authorization to sell electricity
         at market-based rates.  The Commission explained that
                   for all future cases involving blanket
                   approval of market-based rates an offer of

         107/ E.g., CSW, supra 68 FERC at 61,914.
         108/ Id.
         109/ Id. at 915 (footnote omitted).
         110/ 68 FERC ¶ 61,223 (1994).
         Docket Nos. RM95-8-000
           and RM94-7-001               -55-
                   comparable transmission services will be
                   required before the Commission will be able
                   to find that transmission market power has
                   been adequately mitigated.  In the context of
                   an affiliated power marketer, this means that
                   all of its affiliated utilities must have a
                   comparable transmission tariff on file.
                   [111/]
              The Commission also denied a request by a company affiliated
         with a transmission-owning utility seeking permission to sell
         power at market-based rates to a particular customer.  The denial
         was without prejudice to refiling such a request in a new section
         205 proceeding, but only after the affiliated transmission-owning
         utility filed a comparable transmission service tariff. 112/
         The Commission added that it
                   will require comparability in any situation
                   in which a seller seeking market-based rates
                   is affiliated with an owner or controller of
                   transmission facilities. [113/]

         111/ Id. at 62,060.  In InterCoast Power Marketing Company, 68
              FERC ¶ 61,248, clarified, 68 FERC ¶ 61,324 (1994), the
              Commission rejected an affiliated marketer's proposal to
              sell at market rates without its affiliate utility offering
              comparable transmission services.  The Commission stated
              that the only way to ensure that InterCoast does not have
              transmission market power is to require its affiliated
              public utility to offer comparable transmission services.
              See also LG&E Power Marketing Inc., 68 FERC ¶ 61,247 at
              62,120-21 (1994).  The Commission added that this is
              consistent with encouraging competitive bulk power markets
              as envisioned by the Energy Policy Act of 1992.  Id. at
              62,132.
         112/ See Hermiston Generating Company, 69 FERC ¶ 61,035 at 61,164
              (1994), reh'g pending.  The Commission subsequently accepted
              the rates on a cost basis.  See Letter Order dated November
              10, 1994.
         113/ Id. at 61,165.
         Docket Nos. RM95-8-000
           and RM94-7-001               -56-
              The Commission has also stated that "it will henceforth
         apply the transmission comparability standard announced in the
         AEP case to all transmitting utility members of an RTG." 114/
         The Commission further declared that comparable services must be
         provided through "open access" tariffs rather than only on a
         contract-by-contract basis:
                   [T]ariffs are essential to the provision of
                   comparable services.  Tariffs set out the
                   services that are available and the terms and
                   conditions under which those services will be
                   made available....[In contrast], a
                   negotiation process creates uncertainty and
                   imposes on customers delay and other
                   transaction costs that the transmitting
                   utility members of an RTG do not incur when
                   using the transmission for their own benefit.
                   Moreover, the ability to execute separate
                   transmission agreements with different but
                   similarly situated customers is the ability
                   to unduly discriminate among them.  A tariff
                   ensures against such discrimination in the
                   RTG. [115/]   
         Thus, the Commission required the RTGs to amend their bylaws to
         commit all transmitting utility members to offer comparable

         114/ See SWRTA, 69 FERC at 61,397; see also PacifiCorp, the
              California Municipal Utilities Association, and the
              Independent Energy Producers (on behalf of Western Regional
              Transmission Association), 69 FERC ¶ 61,099, order on reh'g,
              69 FERC ¶ 61,352 (1994) (WRTA).  An RTG is a regional
              transmission group.  It is defined as "a voluntary
              organization of transmission owners, transmission users, and
              other entities interested in coordinating transmission
              planning (and expansion), operation and use on a regional
              (and inter-regional."  Policy Statement Regarding Regional
              Transmission Groups, 58 FR 41626 (August 5, 1993), III FERC
              Stats. & Regs., Regulations Preambles ¶ 30,976 at 30,870 n.4
              (RTG Policy Statement).  
         115/ SWRTA, 69 FERC at 61,398.
         Docket Nos. RM95-8-000
           and RM94-7-001               -57-
         transmission services to other RTG members pursuant to a
         transmission tariff or tariffs.
              Most recently, the Commission has set for hearing whether
         transmission tariffs meet the AEP comparability standard in
         Commonwealth Edison Company, 116/ Wisconsin Electric Power
         Company, 117/ and Wisconsin Public Service Corporation.
         118/  In all three cases, the company agreed in principle to
         provide comparable service, but issues arose as to what
         constitutes such service.  
                   c.  Lack of Market Power in New Generation

              In KCP&L, discussed in the prior section, the Commission
         continued to recognize that transmission remains a natural
         monopoly.  However, it found that, in light of the industry and
         statutory changes that now allow ease of market entry, no
         wholesale seller of generation has market power in generation
         from new facilities. 119/  In particular, the Commission
         explained that it had previously noted in Entergy Services, Inc.
         that
                   there was significant evidence that non-
                   traditional power project developers,
                   including qualifying facilities and
                   independent power projects, are becoming

         116/ 70 FERC ¶ 61,204 (1995).
         117/ 70 FERC ¶ 61,074 (1995).
         118/ 70 FERC ¶ 61,075 (1995).
         119/ KCP&L, 67 FERC ¶ 61,183 (1994).
         Docket Nos. RM95-8-000
           and RM94-7-001               -58-
                   viable competitors in long-run markets.
                   [120/]
         The Commission further explained that since Entergy, Congress had
         enacted the Energy Policy Act, which had lowered barriers to the
         entry of new suppliers by creating a new class of power suppliers
         -- EWGs -- that are exempt from the provisions of PUHCA. 121/
         The Commission concluded that, in considering market-based rate
         proposals for generation sales, it need only focus on market
         power in transmission, generation market power in short-run
         markets, and other barriers to entry. 122/
                   d.  Further Commission Action Addressing a More         
                       Competitive Electric Industry
              To address the fact that the electric industry is becoming
         more competitive, and to remove barriers that might inhibit a
         more competitive industry, the Commission has initiated a number
         of additional proceedings:  (1) Stranded Cost Notice of Proposed
         Rulemaking, 123/ (2) Transmission Pricing Policy Statement,

         120/ Id. at 61,557 (citing Entergy Services, Inc., 58 FERC ¶
              61,234 at 61,756 and nn.63 and 65 (Entergy)).
         121/ Id.  The Commission added that "after examining generation
              dominance in many different cases over the years, we have
              yet to find an instance of generation dominance in long-run
              bulk power markets." Id.
         122/ Id.  In KCP&L, the Commission declined to dismiss the
              possibility of market power in generation associated with
              sales out of existing capacity.  As noted, however, we here
              seek comments on whether, and if so under what conditions,
              to drop the generation dominance standard in short-run
              markets, i.e., for sales from existing capacity.
         123/ See supra note 5.  
         Docket Nos. RM95-8-000
           and RM94-7-001               -59-
         124/ (3) Pooling Notice of Inquiry, 125/ and (4) Regional
         Transmission Group (RTG) Policy Statement. 126/
              In the Stranded Cost NOPR the Commission recognized that the
         trend toward greater transmission access and the transition to a
         fully competitive bulk power market could cause some utilities to
         incur stranded costs as wholesale requirements customers (or
         retail customers) use their supplier's transmission to purchase
         power elsewhere.  As the Commission noted, a utility may have
         built facilities or entered into long-term fuel or purchased
         power supply contracts with the reasonable expectation that its
         customers would renew their contracts and would pay their share
         of long-term investments and other incurred costs.  If the
         customer obtains another power supplier, the utility may have
         stranded costs.  If the utility cannot locate an alternative
         buyer or somehow mitigate the stranded costs, the Commission
         explained that "the costs must be recovered from either the
         departing customer or the remaining customers or borne by the

         124/ See Inquiry Concerning the Commission's Pricing Policy for
              Transmission Services Provided by Public Utilities Under the
              Federal Power Act, 59 FR 55031 (November 3, 1994), III FERC
              Stats. & Regs., Regulations Preambles ¶ 31,005 (Transmission
              Pricing Policy Statement).
         125/ See Inquiry Concerning Alternative Power Pooling
              Institutions Under the Federal Power Act, 59 FR 54851
              (October 26, 1994), IV FERC Stats. & Regs., Notices ¶ 35,529
              (1995) (Pooling Notice of Inquiry).
         126/ See Policy Statement Regarding Regional Transmission Groups,
              58 FR 41626 (August 5, 1993), III FERC Stats. & Regs.,
              Regulations Preambles ¶ 30,976 (RTG Policy Statement).
         Docket Nos. RM95-8-000
           and RM94-7-001               -60-
         utility's shareholders." 127/  Accordingly, the Commission
         proposed to establish provisions concerning the recovery of
         wholesale and retail stranded costs by public utilities and
         transmitting utilities. 128/
              In the Transmission Pricing Policy Statement, the Commission
         announced a new policy providing greater flexibility in the
         pricing of transmission services provided by public utilities and
         transmitting utilities.  The Commission traditionally had allowed
         only postage-stamp, contract-path pricing. 129/  Under the
         new policy, it will permit a variety of proposals, including
         distance sensitive and flow-based pricing, 130/ which may be

         127/ Stranded Cost NOPR at 32,864.
         128/ The Commission herein is making preliminary findings on
              stranded costs and issuing a supplemental Stranded Cost
              NOPR, seeking comments on the impact of our proposed open
              access NOPR on stranded costs.
         129/ Most transmission contracts set a single price for energy
              flow over a utility's transmission system.  This single-
              price policy is called "postage stamp" pricing because the
              rate does not depend on how far the power moves within a
              company's transmission system.  If power flows through
              several companies, traditional industry practice is to
              specify that power flows along a "contract path" consisting
              of the transmission-owning utilities between the ultimate
              receipt and delivery points.  See infra discussion of
              Indiana Michigan Power Company, 64 FERC ¶ 61,184.
         130/ Unlike with postage stamp pricing, with distance-sensitive
              pricing the cost of moving power through a company depends
              on how far the power moves within the company.  In contrast
              to contract path pricing, flow-based pricing establishes a
              price based on the costs of the various parallel paths
              actually used when the power flows.  Because flow-based
              pricing can account for all parallel paths used by the
              transaction, all transmission owners with facilities on any
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001               -61-
         more suitable for competitive wholesale power markets.  The
         Commission explained that this "[g]reater 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."
131/
         However, the Commission explained that any new transmission
         pricing proposal must meet the Commission's AEP comparability
         standard.  The Commission further explained that comparability of
         service applies to price as well as to terms and conditions.
         132/
              The Commission issued the Pooling Notice of Inquiry to
         receive comments on traditional power pools and on alternative
         power pooling institutions that are being explored in today's
         more competitive environment.  The Commission expressed concern
         that
                   [g]iven the ongoing changes in the
                   competitive environment of the electric
                   utility industry -- in particular, the
                   potential for substantially increased access
                   to transmission -- we must consider whether
                   we are appropriately balancing our dual
                   objectives of promoting coordination and
                   competition. [133/]

         130/(...continued)
              of the parallel paths would be compensated for the
              transaction.
         131/ Transmission Pricing Policy Statement at 31,136.
         132/ Id. at 31,142.
         133/ Pooling Notice of Inquiry at 35,715.
         Docket Nos. RM95-8-000
           and RM94-7-001               -62-
         Accordingly, the Commission explained that it wished to look at
         alternative power pooling institutions and to re-examine the role
         of more traditional power pools in today's environment of
         increased competition.  In particular the Commission expressed
         its intent to ensure that its policies "are consistent with the
         development of a competitive bulk power market." 134/
              In the RTG Policy Statement, the Commission announced a
         policy encouraging the development of RTGs.   The Commission
         explained that a primary purpose of RTGs is to facilitate
         transmission access for potential users and voluntarily resolve
         disputes over such service.  The Commission has recently
         conditionally approved the formation of two RTGs. 135/  One
         of the conditions is that each RTG member must offer comparable
         transmission services by tariff to other RTG members.
              In addition to the Commission's actions, a number of states
         have initiated proceedings concerning retail wheeling or proposed
         legislation for retail wheeling, that is, for ultimate consumers
         to choose their supplier of power. 136/

         134/ Id. at 35,714.
         135/ See WRTA and SWRTA, supra.
         136/ The Energy Information Administration recently indicated
              that at least nine states -- California, Connecticut,
              Illinois, Michigan, Nevada, Ohio, Texas, Utah, and Vermont
              have proposals or legislation for retail wheeling.  EIA,
              Performance Issues for a Changing Electricity Power
              Industry, January 1995 19-22.  Most prominent among the
              recent state proposals are the California Public Utility
              Commission's "Blue Book" proposal (Order Instituting
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001               -63-
              D.  Need for Reform
              The many changes discussed above have converged to create a
         situation in which new generating capacity can be built and
         operated at prices substantially lower than many utilities'
         embedded costs of generation.  As discussed above, new generation
         facilities can produce power on the grid at a cost of 3 to 5
         cents per kWh, yet the costs for large plants constructed and
         installed over the last decade were typically in the range of 4
         to 7 cents per kWh for coal plants and 9 to 15 cents for nuclear
         plants.  Non-traditional generators are taking advantage of this
         opportunity to compete.  Indeed, the non-traditional generators'
         share of total U.S. electricity generation increased from 4
         percent in 1985 to 10 percent in 1993. 137/  Much of this
         increased share of generation is the result of competitive
         bidding for new generation resources that has occurred in 37
         states.  Since 1984, almost 4,000 projects, representing over
         400,000 MW, have been offered in response to requests.  Over 350

         136/(...continued)
              Rulemaking on the Commission's Proposed Policies Governing
              Restructuring California's Electric Services Industry and
              Reforming Regulation, R. 94-04-031; Order Instituting
              Investigation on the Commission's Proposed Policies
              Governing Restructuring California's Electric Services
              Industry and Reforming Regulation, I. 94-04-032) and the
              Michigan Public Service Commission's proposal (Interim Order
              on Experimental Retail Wheeling Program, Case No. U-10143/U-
              10176 (April 11, 1994)).  
         137/ Energy Information Administration, Performance Issues for a
              Changing Electric Power Industry (January 1995) 10 and
              (Figure 5).
         Docket Nos. RM95-8-000
           and RM94-7-001               -64-
         projects have been selected to supply 20,000 MW, and, of these,
         126 are now online producing almost 7,800 MW of power. 138/
         In addition, the cost of utility-generated electricity differs
         widely across the major regions of the United States.  Average
         utility rates range from 3 to 5 cents in the Northwest to 9 to 11
         cents in California. 139/  Electricity consumers are
         demanding access to lower cost supplies available in other
         regions of the United States, and access to the newer, lower cost
         generation resources.  It is also important that the non-
         traditional generators of cheaper power be able to gain access to
         the transmission grid on a non-discriminatory open access basis.
              The Commission's goal is to ensure that customers have the
         benefits of competitively priced generation.  However, we must do
         so without abandoning our traditional obligation to ensure that
         utilities have a fair opportunity to recover prudently incurred
         costs and that they maintain power supply reliability.  As well,
         the benefits of competition should not come at the expense of
         other customers.  The Commission believes that requiring
         utilities to provide non-discriminatory open access transmission
         tariffs, while simultaneously resolving the extremely difficult
         issue of recovery of transition costs (discussed infra), is the
         key to reconciling these competing demands.  

         138/ Current Competition, November 1994, Vol. 5, No. 8, at 8.
         139/ See map attached as Appendix A. This Appendix will not
              appear in the Federal Register.
         Docket Nos. RM95-8-000
           and RM94-7-001               -65-
              Non-discriminatory open access to transmission services is
         critical to the full development of competitive wholesale
         generation markets and the lower consumer prices achievable
         through such competition. 140/  Transmitting utilities own
         the transportation system over which bulk power competition
         occurs and transmission service continues to be a natural
         monopoly.  Denials of access (whether they are blatant or
         subtle), and the potential for future denials of access, require
         the Commission to revisit and reform its regulation of
         transmission in interstate commerce.  Such action is required by
         the FPA's mandate that the Commission remedy undue
         discrimination.
                   1.  Market Power
              Unlike new generating capacity (see prior discussion of
         KCP&L), transmission remains and is expected to remain a natural
         monopoly.  The Commission has addressed the natural monopoly
         character of transmission in the major cases summarized above and
         in the Commission's recent Transmission Pricing Policy Statement.
              The monopoly characteristic exists in part because entry
         into the transmission market is restricted or difficult. 141/

         140/ As discussed above, only a minimal number of public
              utilities have any form of an "open access" tariff on file
              with the Commission and no public utility has on file a non-
              discriminatory open access tariff as defined by this rule.
         141/ An example of this is that, except in the limited case of
              licensed hydroelectric projects under Part I of the FPA,
              there is no Federal right of eminent domain available to
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001               -66-
         In addition, as unit costs are less for larger lines and
         networks, transmission facilities still exhibit scale economies.
         From an economic, environmental, and aesthetic viewpoint, it is
         often better for a single owner (or group of owners) to build a
         single large transmission line rather than for many transmission
         owners to build smaller parallel lines on a non-coordinated
         basis.
              Further, effective competition among owners of parallel
         transmission lines is unlikely, and often impossible, with
         existing practices and technology.  For example, on an
         alternating current (AC) electric system, electricity flows on
         parallel paths based on the impedance of each path.  With two
         electric systems providing parallel contract paths, a share of
         the actual power flows would occur on each system according to
         the physical characteristics of the system.  Thus, each of the
         two transmission service providers would have the incentive to
         underbid the other because the winner would receive all of the
         transmission revenues, but only incur a fraction of the costs.
         The loser, on the other hand, would incur the remaining costs,
         but would receive no revenues.      
              In today's electric industry, which is dominated by
         vertically integrated utilities, an owner or controller of

         141/(...continued)
              assist in acquiring rights of way for new transmission
              lines.  In addition, the regulatory requirements to build a
              transmission line vary from state to state.  In all states,
              siting new transmission lines is getting harder.
         Docket Nos. RM95-8-000
           and RM94-7-001               -67-
         transmission service can exclude generation competitors from the
         market, thereby favoring the transmission owner's own generation.
         This can occur through outright denial of transmission access,
         or, as is more likely, through access that is discriminatory as
         to rates, terms or conditions of service. 142/  Thus, in the
         absence of non-discriminatory open access tariffs, the
         development of fully competitive bulk power markets cannot occur,
         and consumers will be deprived of the benefits that would be
         expected from such a competitive market.
                   2.  Discriminatory Access
              Some transmission-owning utilities have voluntarily begun to
         offer unbundled transmission tariff services to third-party
         suppliers and purchasers of wholesale power, though none have
         done so to the extent proposed by this proposed rule. 143/  
         However, because utilities are naturally profit maximizers and
         monopoly suppliers to their native load, the vast majority of
         transmission-owning utilities have not agreed to give up their
         market power voluntarily.  Transmission-owning utilities have an

         142/ See, e.g., David W. Penn, A Municipal Perspective on
              Electric Transmission Access Questions, Pub. Util. Fort. 18-
              19 (Feb. 6, 1986).
         143/ The majority have offered only point-to-point services.
              However, a few utilities have sought to comply with the non-
              discrimination (comparability) standard announced in AEP.
              For example, Kansas City Power & Light Company (KCP&L) and
              Louisville Gas & Electric Company (LG&E) recently filed
              settlements to this effect.  KCP&L, Docket No. ER94-1045
              (settlement filed February 14, 1995) and LG&E, Docket No.
              ER94-1380 (settlement filed February 10, 1995).   
         Docket Nos. RM95-8-000
           and RM94-7-001               -68-
         incentive to deny access either by not filing any open access
         tariff or by filing a tariff that offers services inferior to
         those used by the transmission owner.  This is particularly true
         for those utilities that emerged from the recent decades of
         technological and legal changes as high-cost generation
         companies.  Open access transmission places their existing
         generation at risk because their wholesale customers may seek
         alternative lower price suppliers.  It is in their self-interest
         to maintain and use market power to retain (or expand) market
         share for their existing generation facilities, at least until
         they can get their generation costs in line with current market
         prices.  Because generating units are usually depreciated over a
         30- to 50-year physical life, many high cost companies may
         attempt to exercise transmission market power for decades to
         preserve the value of past generation investments.  
              Unless all public utilities are required to provide non-
         discriminatory open access transmission, the ability to achieve
         full wholesale power competition, and resulting consumer
         benefits, will be jeopardized.  If utilities are allowed to
         discriminate in favor of their own generation resources at the
         expense of providing access to others' lower cost generation
         resources by not providing open access on fair terms, the
         transmission grid will be a patchwork of open access transmission
         systems, systems with bilaterally negotiated arrangements, and
         systems with transmission ordered under section 211.  Under such
         Docket Nos. RM95-8-000
           and RM94-7-001               -69-
         a patchwork of transmission systems, sellers will not have access
         to transmission on an equal basis, and some sellers will benefit
         at the expense of others.  The ultimate loser in such a regime is
         the consumer.
              A patchwork of transmission systems will also result in
         inefficiencies across the Nation's transmission grids.  Because
         of the physical properties of the transmission system, electric
         power moves over parallel transmission lines from generator to
         load, without regard to whether a line is part of a system
         providing open access or not. 144/  However, today the
         industry develops transmission contracts as if power flowed along
         one series of lines belonging to specific owners, which is called

         144/ In Indiana Michigan Power Company, 64 FERC ¶ 61,184 (1993),
              the Commission explained loop flows and parallel power
              flows:
                   In general, utilities transact with one
                   another based on a contract path concept.
                   For pricing purposes, parties assume that
                   power flows are confined to a specified
                   sequence of interconnected utilities that are
                   located on a designated contract path.
                   However, in reality power flows are rarely
                   confined to a designated contract path.
                   Rather, power flows over multiple parallel
                   paths that may be owned by several utilities
                   that are not on the contract path.  The
                   actual power flow is controlled by the laws
                   of physics which cause power being
                   transmitted from one utility to another to
                   travel along multiple parallel paths and
                   divide itself among those paths along the
                   lines of least resistance.  This parallel
                   path flow is sometimes called "loop flow."
              Id. at 62,545.
         Docket Nos. RM95-8-000
           and RM94-7-001               -70-
         the "contract path."  Thus, transmission users will search for
         contract paths through open access systems to take advantage of
         the non-discriminatory open access tariffs.  Because open access
         transmission tariffs include an obligation to expand when
         necessary to accommodate third-party requirements for service,
         transmitting companies offering open access services across their
         systems could end up constructing a disproportionate share of new
         transmission facilities.  
              Expansion cannot be efficient under such a patchwork of open
         access transmission systems.  Not only would this misallocate
         cost burdens to open access companies, but it is unlikely that
         the optimal transmission development will always be within their
         service territories.  Expansion on closed systems, instead of
         open systems, may in some cases be the more efficient way to
         relieve constraints.  Thus, a patchwork of open access systems
         will not result in the least cost expansion of the Nation's
         transmission grids.  In addition, states with open access
         utilities may refuse to site new lines if their closed access
         neighbors are not doing their share. 145/
              A discriminatory, patchwork system also works against   
         pricing parallel power flows on a sensible regional basis.  The
         formation of effective regional transmission groups, which the

         145/ The Commission partially addressed this concern by allowing
              reciprocity provisions in open access transmission tariffs.
              See, e.g., Southwestern Electric Power Company and Public
              Service Company of Oklahoma, 65 FERC ¶ 61,212 at 61,981-82
              (1993), order on reh'g, 66 FERC ¶ 61,099 (1994).
         Docket Nos. RM95-8-000
           and RM94-7-001               -71-
         Commission strongly encourages, would be fostered if all
         utilities in a region offered non-discriminatory open access.
         146/ In fact, optimal cooperative regional action would
         involve all transmission systems in the region offering non-
         discriminatory open access to all wholesale customers.  
              A transmission-owning utility may deny access to third
         parties not only to avoid losing its own generation sales, but
         also to maintain other trading gains.  For example, a company can
         buy low cost power for its own use from a neighbor at a low price
         if other buyers cannot reach that neighbor to bid up the price.
         Furthermore, if it does not need the energy, it can market that
         power by buying low and selling high.
              In the past, transmission-owning utilities have
         discriminated against others seeking transmission access.  
         Transmission-owning utilities have denied access by outright
         refusals to deal.  While such actions tend to be rare, likely
         because transmission owners fear they may trigger antitrust
         action, 147/ they have occurred. 148/  More often,

         146/ While the Commission has conditioned its approval of RTGs to
              achieve this same result, the formation of RTGs is
              voluntary.  By contrast, compliance with the final rules
              adopted in this proceeding will be required.
         147/ See, e.g., Penn, supra note 142, at 18.
         148/ Otter Tail Power Company refused to wheel power for the
              village of Elbow Lake.  The Supreme Court ultimately ruled
              against Otter Tail on antitrust grounds.  Otter Tail Power
              Company, 410 U.S. 366 (1974).  The Commission has also found
              that Utah Power & Light Company consistently refused to
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001               -72-
         however, discrimination is likely to be manifested more subtly
         and indirectly. 149/  One such way would be for transmission
         owners to adopt a negotiating strategy that involves a sequence
         of informational and other requirements over a protracted period
         of time.  By the time all of the requirements are finally
         satisfied, the window for the customer's trade opportunity has
         closed. 150/  Another way of frustrating access is to
         substantially change the terms of negotiated agreements through
         protracted delay, including filings with regulatory agencies.
         151/

         148/(...continued)
              permit the wheeling of low-cost power across its system in
              order to use its strategically located bottleneck
              transmission system to extract monopoly prices.  Utah Power
              & Light Company, supra, 45 FERC at 61,287 and n.137 (1988).
         149/ See, e.g., Penn, supra note 142, at 18-19 (discussion of
              methods used to deny access).  Penn also noted in his 1986
              article that the American Public Power Association had
              conducted a survey of its members in which about 25%
              indicated a problem in securing transmission in effecting
              coordination services and about an equal amount had reported
              being denied transmission access in the recent past.  Id. at
              18.  See also Pacific Gas & Electric Company, 51 FPC 1030,
              1031-32, reh'g denied, 51 FPC 1543 (1974) (parties alleged
              that public utility proposed "a wholesale rate so high that
              its wholesale customers would be unable to compete with PG&E
              for large industrial retail loads" and entered into
              restrictive and anticompetitive contracts that strengthened
              public utility's monopoly).  
         150/ Members of the Coalition for a Competitive Electricity
              Market alleged that they have encountered this strategy.
              Coalition Petition at 13, n.19.
         151/ An example of this tactic is evident in the history of
              Pacific Gas and Electric Company's (PG&E) attempt to avoid
              its commitments made to the California owners of the
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001               -73-
              Another way for transmission-owning utilities to frustrate
         access and competition is to allow access, but only on non-
         comparable or unsupportable terms and conditions that are
         inferior to the conditions under which the transmission owners
         themselves use or could use the transmission grid or on terms and
         conditions that have no operational or financial basis.
         Discrimination can be exercised this way in the following areas:
                   (1)  Network Service.  Network service allows
                   a transmission customer to distribute a given
                   amount of transmission usage between
                   specified resources and specified loads
                   without having to pay multiple charges for
                   each resource-load pairing.  Transmission
                   owners can refuse to provide service on these
                   terms and instead insist on charges that are
                   a function of the number of resource load

         151/(...continued)
              California-Oregon Transmission Project (COTP).  The owners
              had originally planned the COTP to have its southern
              terminus at the Midway station with Southern California
              Edison.  PG&E convinced them to terminate the project
              instead at PG&E's Tesla station and indicated that PG&E
              would provide transmission service the rest of the way south
              to Midway.  PG&E promised this service in 1989 (in what came
              to be known as the South of Tesla Principles).  PG&E spent
              the next four years filing substitute provisions for what it
              had promised in the Principles.  See Pacific Gas and
              Electric Company, 65 FERC ¶ 61,312 at 62,428-30 and n.22,
              remanded on other grounds , Pacific Gas & Electric Company
              v. FERC, No. 94-70037 (9th Cir. June 23, 1994) (unpublished
              opinion), order on remand, 69 FERC ¶ 61,006 (1994).
         Docket Nos. RM95-8-000
           and RM94-7-001               -74-
                   pairings. 152/  This can dramatically
                   increase the cost of such service.  Such
                   treatment does not reflect the way
                   transmission owners' costs are allocated to
                   their own native load customers.
                   (2)  Pricing.  Transmission service can be
                   made unattractive to third-party customers by
                   pricing such service on a basis that is
                   different from that used by the transmission
                   owner and that results in higher rates.  One
                   example would be charging third-party
                   customers distance-sensitive rates, while
                   pricing all similar transmission bundled with
                   power services on a postage stamp basis.
                   153/

         152/ See Pacific Gas and Electric Company, 52 FERC ¶ 61,347 at
              62,375-76 (1990) (proposal to charge a base demand and a
              flexibility adder for an integrating transmission service).
              PG&E eventually withdrew the proposal. 56 FERC ¶ 61,373 at
              62,429 (1991); see also Florida Municipal Power Agency v.
              Florida Power & Light Company, 65 FERC ¶ 61,125 (1993)
              (Federal Municipal Power Agency requested a section 211
              order directing network service); Tex-La Electric
              Cooperative of Texas, 67 FERC ¶ 61,019 at 61,057 (1994)
              (Tex-La requested a section 211 order directing network
              service).
         153/ See notes 129 and 130, supra; see also Tex-La Electric
              Cooperative of Texas, 69 FERC ¶ 61,269 at 62,034-35 (1994),
              in which the Commission found this practice to be unduly
              discriminatory.
         Docket Nos. RM95-8-000
           and RM94-7-001               -75-
                   (3)  Service Priority.  The priority of
                   transmission service is a critical service
                   factor.  The transmission provider could
                   disadvantage third-party transmission
                   customers by making firm transmission service
                   to them subordinate to the transmission
                   utility's native load service. 154/
                   (4)  Scheduling and Balancing Provisions.  A
                   transmission owner could hold transmission
                   customers to unnecessarily long lead times to
                   change power schedules.  In some cases,
                   scheduling could be required as much as a
                   month ahead of time. 155/  This precludes
                   transmission customers from using their
                   service for short-term trading.  Transmitting
                   utilities may also insist that customers keep
                   strict adherence to scheduling and balancing
                   provisions by requiring them to get back on
                   schedule quickly or face stiff penalties.
                   156/  One example of a stiff penalty for
                   failure to schedule sufficient power would be
                   to assess shortfalls based on a partial

         154/ See AEP, 64 FERC at 62,971-72.
         155/ Id.
         156/ See Coalition Petition at 20-21.
         Docket Nos. RM95-8-000
           and RM94-7-001               -76-
                   requirements rate with an 11-month ratchet.
                   157/  In contrast, transmitting utilities
                   may have access to less costly balancing
                   alternatives, such as substituting resources
                   without notice or borrowing capacity from
                   neighboring utilities and settling the
                   imbalance by returning energy in-kind within
                   a much longer time period than allowed to
                   customers. 158/
                   (5)  Use of Firm Transmission Capacity.
                   Transmission owners can unnecessarily
                   restrict the firm transmission capacity made
                   available to transmission customers.  One way
                   to restrict service would be to prohibit the
                   customer from reassigning such capacity when
                   it is not needed. 159/  This restricts
                   the customer's ability to manage the risk of
                   long-term capacity purchases and to compete

         157/ See Borough of Zelienople, 70 FERC ¶ 61,073 at 61,184 (1995)
              (load exceeding schedule by 1 MW would be filled at a
              partial requirements rate using a 60% demand ratchet for 11
              months, i.e., 1 MW times 60% times $9.30 per kW times 11,
              for a total of $61,380).
         158/ See Coalition Petition at 20-21.
         159/ See, e.g., Pacific Gas and Electric Company, 53 FERC ¶
              61,145 at 61,505 (1990) (utility proposed a reassignment
              prohibition on the use of Reserve Transmission Service
              available to the Sacramento Municipal Utility District under
              a proposed Interconnection Agreement).
         Docket Nos. RM95-8-000
           and RM94-7-001               -77-
                   as a seller in the transmission service
                   market.  Another example would be that the
                   transmission owner could restrict a
                   customer's use of transmission capacity by
                   allowing sales only from the customer's
                   generating resources that are temporarily in
                   excess of actual load needs. 160/
                   Transmission owners do not face these
                   restrictions in their own use of transmission
                   capacity.
                   (6)  Ancillary Services.  A transmitting
                   utility may offer to a transmission customer
                   ancillary services (e.g., scheduling) that
                   are inferior to the services it provides for
                   itself.  Transmission owners may be free to
                   choose whether to supply some of these
                   services to themselves or contract for them
                   if available more cheaply elsewhere. 161/
                   Third-party transmission customers do not
                   always have this option on a comparable
                   basis.

         160/ Id. at 61,504-05 (utility proposed an export restriction on
              the use of Reserve Transmission Service available to the
              Sacramento Municipal Utility District under a proposed
              Interconnection Agreement).
         161/ See Coalition Petition at 28-29 and 32.
         Docket Nos. RM95-8-000
           and RM94-7-001               -78-
                   (7)  Creditworthiness and Security Deposits.
                   Customers are sometimes required to make
                   onerous deposits in order to obtain service.
                   162/
                   (8)  Reciprocity Double Payments.
                   Transmission agreements often require
                   reciprocity.  Non-transmission owners could
                   be required to contract with, and pay, third-
                   party transmitting utilities to provide the
                   required reciprocal service. 163/
                   Transmission owners do not face such
                   obstacles in using their own systems.
              Finally, an additional way for transmission-owning utilities
         to frustrate access and competition is by granting each other
         superior rights and lower rates -- compared to those available to
         non-transmission owning customers -- in pools, interconnection
         agreements, and other protocols. 164/  For example, pool-wide
         transmission service can be made available to members at rates
         less than those that each member would separately propose under

         162/ For example, it is reported that one customer was told that
              a $13 million line of credit would be required to ensure
              creditworthiness for a request of only one MW of
              transmission capacity for a coordination trade.  See
              Coalition Petition at 30.
         163/ See Coalition Petition at 25; see also AES Power, Inc., 69
              FERC ¶ 61,345 at 62,295 and 62,301 (1994) (AES).
         164/ See Coalition Petition at 13-14.
         Docket Nos. RM95-8-000
           and RM94-7-001               -79-
         traditional rate methods.  This could disadvantage non-
         transmission owners if pool membership is restricted or if it
         requires excessive or vaguely stated transmission contributions
         that could be difficult to meet. 165/        
              Section 211 is not always a sufficient remedy for this
         discriminatory behavior.  Third parties may seek non-
         discriminatory transmission under section 211, but they will not
         be able to compete if the sale or purchase opportunity is gone
         before a final order can be obtained under section 211.  This
         could be the case in many situations because of the procedural
         requirements of sections 211 and 212. 166/  Indeed, to date,
         the Commission has received eighteen section 211 transmission
         requests, 167/ which it has tried to process expeditiously
         within the procedural constraints contained in sections 211 and
         212.  As to the seven requests that have received a final order,
         the average elapsed time from date of filing to the date of a
         final order was 9 months.  The remaining ten requests have been

         165/ See Mid-Continent Area Power Pool, 69 FERC ¶ 61,347 at
              62,308 (1994).
         166/ For example, an applicant must make a request for
              transmission service to the transmitting utility at least 60
              days before filing an application with the Commission for an
              order to provide transmission.  The Commission must first
              issue a proposed order and allow the parties a reasonable
              time to negotiate agreeable terms and conditions before it
              can issue a final order.  Moreover, a final order faces
              possible rehearing and a court appeal.
         167/ One request was withdrawn.
         Docket Nos. RM95-8-000
           and RM94-7-001               -80-
         pending, on average, more than 6 months. 168/  
              As the wholesale power markets become more competitive,

         168/ The following sets forth the status of the section 211 cases
         filed with the Commission:
                              Date of                           Months
         Docket Number       Application    Status              Pending
         TX93-1              01/19/93       Final Order-7/29/93      6
         TX93-2              06/18/93       Final Order-7/1/94      12
         TX93-3              06/30/93       Withdrew-9/10/93         2
         TX93-4              07/02/93       Final Order-5/11/94     10
         TX94-1              10/21/93       Final Order-7/6/94       9
         TX94-2              11/04/93       Pending *               16
         TX94-3              11/09/93       Final Order-7/13/94      8
         TX94-4              12/15/93       Final Order-12/1/94     11
         TX94-5              04/15/94       Final Order-3/23/95     11
         TX94-6              07/05/94       Pending                  8
         TX94-7              07/15/94       Pending *                8
         TX94-8              08/05/94       Pending                  7
         TX94-9              09/09/94       Pending *                6
         TX94-10             09/16/94       Pending                  6
         TX95-1              10/11/94       Pending                  5
         TX95-2              10/17/94       Pending                  5
         TX95-3              01/19/95       Pending                  2
         TX95-4              01/24/95       Pending                  2
         *  A proposed order has been issued.
         Docket Nos. RM95-8-000
           and RM94-7-001               -81-
         delayed access becomes a matter of increasing concern.   Not only
         have long-term purchases from non-traditional generators become
         more important, but short-term firm and non-firm power sales and
         purchases create significant profit or cost-saving opportunities
         for utilities, marketers, and their customers.  As a result,
         market participants are exploring various ways to reduce their
         costs through trading.  These include poolcos, changes to
         existing pools, short-term trading systems, and futures
         contracts. 169/  We do not see how such options will work
         unless all parties have non-discriminatory transmission access
         rights and hour-to-hour access without having to go through a
         regulatory proceeding for each trade.
              In today's emerging competitive wholesale power markets, the
         practices of some transmission-owning utilities are unduly
         discriminatory and anticompetitive.  These practices produce
         market distortions today, undermine the goal of the Energy Policy
         Act to create competitive bulk power markets, and will continue
         if this Commission does not take action.  Most important, they
         can harm consumers by denying them the benefits of competitively

         169/ We note that NEPOOL and MAPP are currently exploring ways to
              modify their pool structures to accommodate competitive
              power markets.  As noted in the Pooling Notice of Inquiry,
              supra, the poolco concept basically involves an independent
              entity that would control the operation of all transmission
              facilities and some or all generating facilities in a
              region.  It would be open and would provide transmission
              service to all generators.  Thus, the poolco would create a
              spot market for power in the region.
         Docket Nos. RM95-8-000
           and RM94-7-001               -82-
         priced power.  We seek additional specific examples of such
         practices.
                   3.  Analogies to the Natural Gas Industry
              The electric industry today is analogous in many ways to the
         natural gas industry before the Commission issued Order Nos. 436
         and 636. 170/  Then, natural gas pipelines were primarily
         merchants offering a bundled sales service, which provided gas to
         customers at the city-gate from the pipelines' own system
         supplies.  In addition, pipelines moved a relatively small amount
         of third-party gas under a separate transportation service.  To
         meet their sales service obligations, pipelines purchased most of
         their system supply from third-party producers under long-term
         contracts.  In the early 1980s, due to changing market
         conditions, the prices under many of these contracts ended up
         being higher than those available in the then evolving spot
         market.  Because of the long-term contracts and the resulting
         higher cost gas, system supply gas tended to be more costly than
         gas that the customers could buy in the competitive spot market.
         At the same time, the transportation service bundled with a
         pipeline's sales service was usually superior to the

         170/ Order No. 436, Regulation of Natural Gas Pipelines After
              Partial Wellhead Decontrol, FERC Regulations Preambles ¶
              30,665 (1985); Order 636, Pipeline Service Obligations and
              Revisions to Regulations Governing Self-Implementing
              Transportation Under Part 284 of the Commission's
              Regulations; and Regulation of Natural Gas Pipelines After
              Partial Wellhead Decontrol, 57 FR 13267 (April 16, 1992),
              III FERC Stats. & Regs., Regulations Preambles ¶ 30,939
              (Order No. 636), appeal pending.
         Docket Nos. RM95-8-000
           and RM94-7-001               -83-
         transportation service third parties could obtain.  Essentially,
         the pipeline would provide itself service that had much greater
         flexibility and often promised greater reliability than that
         available to third-party shippers.  Pipelines had a considerable
         incentive to maintain this difference in transportation service
         quality to make their own, more expensive gas more attractive.
              A similar situation exists today in the electric industry.
         Traditional public utilities deliver bundled service --
         generation and transmission -- to most of their wholesale
         customers.  They have monopoly control over transmission
         facilities and thus control access to their customers.  The lack
         of non-discriminatory access to transmission services raises the
         same general concerns that were prevalent in the gas industry.
         Accordingly, unless similar regulatory measures are undertaken,
         the Commission expects the same type of discriminatory and
         anticompetitive behavior will continue in the electric industry
         as was present in the gas industry, because denying non-
         discriminatory access will continue to be in the economic self-
         interest of transmission monopolists, absent regulatory changes.
         171/   
              In its regulation of interstate pipelines under the Natural
         Gas Act (NGA) the Commission initially addressed the problem of

         171/ See AGD, supra, 824 F.2d at 1008 ("Agencies do not need to
              conduct experiments in order to rely on the prediction that
              an unsupported stone will fall.").  The ongoing
              discriminatory behavior by owners or controllers of
              transmission in the electric industry is detailed supra.
         Docket Nos. RM95-8-000
           and RM94-7-001               -84-
         undue discrimination in Order No. 436, finding natural gas
         pipeline practices to be unduly discriminatory under the NGA
         172/ and effectuating "open access" transportation.  The
         Commission in that order sought to make transportation available
         to third parties on a non-discriminatory basis.  The Commission
         provided that, if a pipeline held itself out as a transporter of
         gas for others, it must provide that service to all shippers
         without discrimination.  At the same time, the Commission allowed
         pipelines and their customers to retain the traditional bundled
         sales and transportation services under existing certificate
         authority.
              As a result of Order No. 436, pipelines became primarily
         transporters of natural gas.  However, in Order No. 636, the
         Commission noted that pipelines were still providing, albeit at a
         reduced level, a bundled, city gate, sales service in competition
         with third-party sales and transportation, and concluded that the
         competition was not occurring on an equal basis.  The Commission
         also noted that pipelines' natural gas sales prices exceeded
         those of their competitors, much as electric utilities' embedded
         costs can exceed the cost of new generating capacity and excess
         generating capacity of others.  In this regard, the Commission
         determined that the transportation service bundled with
         pipelines' sales service was superior to that made available to

         172/ In this regard, sections 4 and 5 of the NGA are virtually
              identical to sections 205 and 206 of the FPA.
         Docket Nos. RM95-8-000
           and RM94-7-001               -85-
         third parties and that pipelines and unregulated competitors were
         not selling the same product. 173/  Accordingly, in Order No.
         636, the Commission found this behavior anticompetitive and
         required pipelines to "unbundle" their sales services from their
         transportation services and to provide open access transportation
         service that is equal in quality for all gas supplies whether
         purchased from the pipeline or some other supplier. 174/  
              Our experience in the gas area influences our decision that,
         at a minimum, functional unbundling of wholesale services is
         necessary in order to obtain non-discriminatory open access and
         to avoid anticompetitive behavior in wholesale electricity
         markets.
                   4.  Coordination Rates
              In finding a need for non-discriminatory open access
         transmission, the Commission has considered the structure of the
         coordination market, i.e., the market for wholesale sales to a
         public utility's non-requirements customers.  Utilities now
         engage in coordination trades primarily under rates no lower than
         the seller's variable cost and no higher than that variable cost
         plus 100% contribution to the fixed costs of the production unit

         173/ Order No. 636 at 30,402.  The Commission explained that
              pipelines were selling a regulated bundled sales and
              transportation service, but that their competitors were
              generally selling only the gas commodity.  The Commission
              also recognized that pipelines were at a competitive
              disadvantage due to their certificate and contractual
              obligations to their firm sales customers.  Id. at 30,403.
         174/ Order No. 636 at 30,393-94.  
         Docket Nos. RM95-8-000
           and RM94-7-001               -86-
         used to price energy and the relevant transmission facilities.
         This rate flexibility allows the buyer and seller to negotiate a
         price reflecting the market at the time of the sale, including
         the number of buyers and sellers, the relative incremental and
         decremental variable costs, and the amount of savings attainable
         by transacting.  Thus, while the seller's ceiling rate reflects
         some measure of fixed and variable costs, the actual transaction
         price is set, to a certain extent, by the marketplace.  This
         marketplace, however, may be skewed by the general lack of
         transmission access, and the resulting price may be considerably
         above prices in a fully competitive market.
              Some utilities transact under a split-savings rate that
         generally sets the price halfway between the seller's incremental
         variable cost and the buyer's decremental variable cost.  Here
         again, price is a function of the alternatives reachable through
         the transmission grid at the time of the transaction.  This rate
         form is primarily used today to distribute the savings derived
         from the central dispatch of power pools on an after-the-fact
         basis.
              The Commission believes that unless the participants in
         coordination markets mitigate their transmission market power,
         market-driven prices for coordination trades may no longer be
         just and reasonable.  Thus, our preliminary conclusion is that
         current coordination pricing is no longer justified in the
         absence of a tariff offer of non-discriminatory open access
         Docket Nos. RM95-8-000
           and RM94-7-001               -87-
         transmission services by the seller (owning or controlling
         transmission) in a coordination transaction. 175/  The
         Commission's past practice of allowing such pricing for
         coordination trades appears to be inconsistent with emerging
         competitive markets unless those who benefit from such trading
         offer access to other, lower-priced trading opportunities.  We
         seek comments on this issue.
              E.  The Proposed Regulations
              The goals of the proposed regulations are two-fold:  (1) to
         facilitate the development of  competitive wholesale bulk power
         markets by ensuring that wholesale purchasers of electric energy
         and wholesale sellers of electricity can reach each other by
         eliminating anticompetitive practices and undue discrimination in
         transmission services; and (2) to address the transition costs
         associated with the development of competitive wholesale markets.
         This section addresses the elimination of undue discrimination.
         Transition costs are addressed below in Section F.
              Non-discriminatory open access transmission is critical to
         the ability of sellers to compete on a fair basis and the ability
         of purchasers to reach the lowest priced generation options.
         Thus far, the Commission has developed an open access
         comparability requirement on a case-by-case basis.  We have
         directed our administrative law judges, to whom the various cases

         175/ As discussed infra, sellers must also meet the Commission's
              other requirements to obtain market-based rates.
         Docket Nos. RM95-8-000
           and RM94-7-001               -88-
         have been referred, to examine the factual circumstances
         surrounding a utility's use of its own system vis-a-vis the type
         of service provided to third parties.  Nonetheless, it has now
         become evident to us that it is necessary for the Commission to
         define the parameters of a non-discriminatory open access tariff
         much more precisely.
              Until now, we have been applying the new standard of what
         constitutes undue discrimination only to new voluntary tariff
         filings.  We now no longer believe it is appropriate to apply
         this standard so narrowly; therefore, we are proposing to require
         all public utilities to offer non-discriminatory open access
         services in accord with the proposed rule and the attached
         tariffs.  This broad application is consistent with our
         determination that undue discrimination by jurisdictional public
         utilities must be prevented or remedied.  It is also consistent
         with our desire to bring further efficiencies to the provision of
         electric service by encouraging competitive bulk power markets.
                   1.  Non-discriminatory Open Access Tariff Requirement
              Transmission owners can discriminate by restricting access
         to, or restricting expansion of, transmission facilities, or by
         restricting access to the ancillary services that control the
         generation resources on the transmission grid. 176/  To

         176/ Examples of ancillary services (which include control area
              services) are:  scheduling service between control areas,
              and various services that facilitate power movements within
              control areas, e.g., dispatch service, load following
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001               -89-
         ensure that all participants in wholesale electricity markets
         have non-discriminatory open access to the transmission network,
         transmission owners must offer non-discriminatory open access
         transmission and ancillary services to wholesale sellers and
         purchasers of electric energy in interstate commerce. 177/
         This will require tariffs that offer point-to-point and network
         transmission services, including ancillary services.  All of
         these services must be non-discriminatory as to price as well as
         to non-price terms and conditions.  Services must be available to
         any entity that could obtain transmission services under section
         211.
              In our AEP rehearing order and in several subsequent cases,
         178/ we set for hearing the following issues:   

         176/(...continued)
              service, imbalance resolution service, reactive power
              support, and operating reserves.  We invite comment on
              definitions of these terms and their component parts.
              Regardless, the proposed rule would require that all
              ancillary services be offered on a non-discriminatory basis.
         177/ See generally William W. Hogan, Reshaping the Electricity
              Industry, Prepared for the Federal Energy Bar Conference,
              "Turmoil for the Utilities," 5 Washington, D.C. (Nov. 17,
              1994):
                   Commercial functions must facilitate non-
                   discriminatory, comparable open access and support
                   market operations in the competitive sectors.  The
                   EPAct requirements and the FERC implementation
                   emphasize the need to obtain market access under terms
                   and conditions that support competition.  Everyone
                   should have equal access to and use of essential
                   facilities, particularly transmission, with the rights
                   of ownership limited to compensation consistent with
                   opportunity costs in a competitive market.
         178/ See, e.g., AEP, 67 FERC at 61,491.
         Docket Nos. RM95-8-000
           and RM94-7-001               -90-
                   1.  The different uses that a transmission
                   owner makes of its transmission system and
                   whether there are any operational differences
                   between any particular use that the owner
                   makes of the system and the use third parties
                   might need, and in particular, the degree of
                   flexibility the transmission owner accords
                   itself in using its transmission system for
                   different purposes.

                   2.  Any potential impediments or consequences
                   to providing a particular service to third-
                   party transmission customers which is the
                   same or comparable to service that the
                   transmission owner provides itself.
                   3.  The costs that the transmission owner
                   incurs in providing transmission associated
                   with its use of the system, and whether the
                   costs to provide such service or comparable
                   service to third parties would be different.
         Based on what we have learned in the past year, the Commission
         proposes to address these issues generically.  Concurrently with
         this order, the Commission is issuing a separate order on how a
         final rule would apply to pending cases. 179/  We believe
         that the parties and the administrative law judges in the
         individual pending proceedings should continue their efforts, but
         in doing so should take into account the principles announced in
         this proposed rule.  This will permit any fine tuning of the
         broader principles announced here and set forth in the pro forma
         tariffs that may be necessary to recognize the individual
         circumstances of particular systems.  
              With regard to the first issue, the Commission believes that

         179/ Order Providing Guidance Concerning Pending and Future
              Proceedings involving Non-discriminatory Open Access
              Transmission Services, Docket Nos. ER93-540-000, et al.
         Docket Nos. RM95-8-000
           and RM94-7-001               -91-
         all utilities use their own systems in two basic ways:  to
         provide themselves point-to-point transmission service that
         supports coordination sales, and to provide themselves network
         transmission service that supports the economic dispatch of their
         own generation units and purchased power resources (integrating
         their resources to meet their internal loads). 180/  This
         network transmission service is bundled as part of retail service
         and as part of wholesale requirements service, and is the
         fundamental support of a utility's dispatch that underlies its
         trading in the wholesale coordination market. 181/
              The Commission has preliminarily concluded that third
         parties may need one or both of these basic uses in order to
         obtain competitively priced generation or to have the opportunity
         to be competitive sellers of power.  The Commission therefore
         proposes that all public utilities must offer both firm and non-
         firm point-to-point transmission service and firm network

         180/ While there may be any number of specific services used
              by a particular customer, we have concluded, after
              analyzing the historical types of transmission service
              tariffs on file, as well as the tariffs filed in the
              ongoing comparability proceedings, that all
              transmission services generally fall within these two
              categories.
         181/ A utility's own coordination purchases may involve hourly
              scheduled transfers of fixed blocks of power.  These
              schedules are supported by the utility's own network
              transmission service used for its economic dispatch.
              Consequently, network service is covered by the proposed
              rule because it supports a utility's coordination purchases,
              regardless of whether or not the utility has any
              requirements customers that also would use network service.
         Docket Nos. RM95-8-000
           and RM94-7-001               -92-
         transmission service on a non-discriminatory open access basis in
         accord with the proposed rule and the attached tariffs.     The
         Commission believes that a utility's tariff must offer to provide
         any point-to-point transmission service and network transmission
         service that customers need, even though the utility may not
         provide itself the specific service requested.  For example, a
         utility may not provide itself "wheeling-through" service,
         182/ which is a specific form of point-to-point service.
         However, because "wheeling-through" service is merely a subset of
         basic point-to-point service, which the utility does provide to
         itself, the Commission will require a utility to provide such
         service. 183/  Similarly, a utility may contend that it does
         not provide non-firm point-to-point service to itself because all
         of its transmission investment results in firm entitlements.
         Nonetheless, the utility provides itself with the functional
         equivalent of non-firm service when it uses, subject to
         curtailment or interruption, capacity that is temporarily unused
         by other firm reservation holders.  Therefore, it must offer non-
         firm point-to-point service.
              We will not allow transmission providers to define terms or
         specify transmission uses to erect barriers to fair and equal

         182/ "Wheeling through" refers to transmittal of electric energy
              through a transmitting utility's grid, i.e., entering at one
              point of interconnection and leaving at another.
         183/ This would be true of other services as well.
         Docket Nos. RM95-8-000
           and RM94-7-001               -93-
         competition in power markets, or to engage in undue
         discrimination.
              On the second issue set for hearing in AEP, et al.
         (potential impediments to providing a particular service), we
         believe there are none, except for impediments to siting.
         However, any impediments to siting are the same whether the
         utility is providing service to itself or to a third party.
              On the third issue set for hearing AEP, et al. (the costs of
         providing comparable service), we believe there is no difference
         in the costs incurred by a transmission provider in providing
         transmission to itself or to a third party.  Thus, the
         transmission owner must charge itself and third parties the same
         rates for the use of its system.
              All electricity trade is supported and facilitated in one
         way or another by ancillary services, and transmission services
         may be comprised of many different combinations of ancillary
         services.  Therefore, the Commission will require that such
         ancillary services be offered separately through open access
         tariffs.  These are discussed in detail infra.
              Public utilities that are transmission-only companies or
         transcos, i.e., companies that do not own or control generation,
         do not use their own transmission systems to sell their own
         power.  However, a public utility transco would be required to
         offer open access transmission services  as well as  ancillary
         services.  It would also have to provide a real-time information
         Docket Nos. RM95-8-000
           and RM94-7-001               -94-
         network, as discussed below.  The Commission is also announcing
         certain quality-of-service guidelines to aid in evaluating the
         quality of transmission service that must be provided by public
         utilities.  These are described infra and are reflected in
         proposed pro forma point-to-point and network tariffs attached to
         this notice of proposed rulemaking.  Our preliminary conclusion
         is that the provisions contained in the pro forma tariffs are the
         minimum provisions necessary to meet the requirement of non-
         discriminatory open access.  We seek comments on these tariffs.
                   2.  Implementing Non-discriminatory Open Access:        
                       Functional Unbundling

              The Commission's preliminary view is that functional
         unbundling of wholesale services is necessary to implement non-
         discriminatory open access.  Accordingly, the proposed rule
         requires that a public utility's uses of its own transmission
         system for the purpose of engaging in wholesale sales and
         purchases of electric energy must be separated from other
         activities, and that transmission services (including ancillary
         services) must be taken under the filed transmission tariff of
         general applicability.  The proposed rule does not require
         corporate unbundling (selling off assets to a non-affiliate, or
         establishing a separate corporate affiliate to manage a utility's
         transmission assets) in any form, although some utilities may
         ultimately choose such a course of action.  The proposed rule
         accommodates corporate unbundling, but does not require it.
         Docket Nos. RM95-8-000
           and RM94-7-001               -95-
              Functional unbundling means three things.  First, it means
         that a public utility must take transmission services (including
         ancillary services) for all of its new wholesale sales and
         purchases of energy under the same tariff of general
         applicability under which others take service.  New wholesale
         sales and purchases are those under any contracts executed on or
         after the open access tariffs required by this proposed rule
         become effective.  Non-discriminatory service requires that the
         utility charge itself the same price for these services that it
         charges its third-party wholesale transmission customers.  We
         seek comment as to the appropriate means to enforce this
         requirement, such as a revenue crediting mechanism.
              Second, functional unbundling means that a transmission
         owner must include in its open access tariffs separately stated
         rates for the transmission and ancillary service components of
         each transmission service it provides. 184/  The rates must
         satisfy the Commission's Transmission Pricing Policy Statement.
         Third, functional unbundling means that the public utility, in
         order to provide non-discriminatory open access to transmission
         and ancillary services information, must rely upon the same
         electronic network that its transmission customers rely upon to

         184/ This means that a customer who buys both generation and
              transmission services from the utility will have a
              separately stated rate for the generation, transmission, and
              ancillary services that it purchases.  The rates for
              transmission and ancillary services would be stated in the
              open access tariff.  The rates for the generation service
              would be under a separate rate schedule.
         Docket Nos. RM95-8-000
           and RM94-7-001               -96-
         obtain transmission information about its system when buying or
         selling power.
              For example, the proposed rule requires that a public
         utility unbundle its new wholesale requirements service
         contracts, and its new wholesale coordination purchase
         transactions, and take the firm network transmission component of
         those services under its own firm network transmission tariff.
         Similarly, the proposed rule requires that a public utility
         unbundle any new wholesale coordination sales transactions and
         take the point-to-point transmission component of that service
         under its own point-to-point transmission tariff.  Finally, the
         proposed rule requires that a utility unbundle ancillary services
         and take these services under its network and point-to-point
         tariffs.
              Public utilities also must authorize their power pool agents
         to offer any transmission service available under power pool
         arrangements to all transmission customers.  In addition, public
         utilities that participate in a power pool that acts as a control
         area must authorize the power pool's control center to offer
         ancillary services under a filed tariff, and must take all of
         their control area services from that tariff. 185/  A public
         utility must take dispatch service and other ancillary

         185/ Similarly, public utilities that own transmission, but get
              their ancillary services from another entity must authorize
              that entity to provide ancillary services under a filed
              tariff and must take their ancillary services from that
              tariff.
         Docket Nos. RM95-8-000
           and RM94-7-001               -97-
         transmission services on the same terms and conditions as those
         offered to its transmission customers. 186/   
              The requirement to provide ancillary services and to take
         those services under a tariff is not intended to mandate any
         federal rules that would prescribe the actual merit order of
         dispatch.  Rather, it is a requirement that public utilities
         ensure that dispatch practices and procedures applicable to them
         are also applied to third-party transmission customers.
              The proposed requirement that a public utility take
         transmission service used for wholesale requirements service and
         wholesale coordination transactions under its own filed tariff
         means that all wholesale trade, both that of the public utility
         and its competitors, would be taken under a single wholesale
         transmission tariff.  Our preliminary view is that such a
         requirement places the correct incentives on the public utility
         to file a fair tariff since it must live under those terms for
         wholesale purposes.  The Commission invites comment on its
         approach to functional unbundling.  Will it provide strong enough
         incentives for non-discriminatory access without some form of
         corporate restructuring?  If utilities restructure, how will our
         proposed rules apply to different types of corporate structures?

         186/ The Commission recognizes that the proposal here overlaps
              with the pending Pooling Notice of Inquiry.  However, the
              fundamental non-discrimination requirements of the FPA, and
              therefore the basic requirements of the proposed rule, must
              be applied to power pools in which public utilities
              participate.  This issue is discussed further in the
              Implementation Section, infra.
         Docket Nos. RM95-8-000
           and RM94-7-001               -98-
              While this approach to unbundling creates good incentives
         with respect to wholesale service, it omits retail service.  In
         other words, it does not require the transmission owner to take
         unbundled transmission service under the same tariff as third
         parties in order to serve its retail customers.  This will result
         in service under two separate arrangements -- an explicit
         wholesale transmission tariff filed at the Commission and an
         implicit retail transmission tariff governed by a state
         regulatory body.  It also raises the possibility that the quality
         of transmission service for retail purposes will be superior to
         the quality of transmission service offered for wholesale
         purposes.  
              We seek comment on how this bifurcated approach would affect
         the public utility's incentives to provide non-discriminatory
         open access wholesale transmission service.  For example, will
         planning of incremental transmission facilities be comparable or
         will the transmission provider's retail customers retain an
         advantage from having expansion costs placed on third parties?
         What would be the benefits of an approach that required the
         transmission provider to take unbundled transmission service for
         both wholesale and retail purposes under the same tariff used by
         third-party transmission customers?  Is such an approach
         necessary to ensure that all participants have the same
         incentives to achieve non-discriminatory open access transmission
         Docket Nos. RM95-8-000
           and RM94-7-001               -99-
         service and competitive power markets?  What would be the
         disadvantages, if any, of such an approach?  
              The Commission recognizes that the unbundling of
         transmission for retail purposes would intrude upon matters that
         state commissions have traditionally regulated.  One possible
         approach that would unify service standards for wholesale and
         retail service would be for each vertically integrated utility to
         establish a distribution function that would be responsible for
         obtaining transmission service on behalf of retail customers.
         This distribution function then could be treated just as any
         other wholesale customer.  The distribution function of the
         utility would take service under the single Commission filed
         tariff.  This could change the traditional approach of state-
         federal allocation of transmission costs.  The Commission seeks
         comment on the merits of such an approach.  How could the
         Commission cooperate with state commissions if it were to adopt
         such an approach?  
              Finally, we address a specific type of retail service that
         we believe to be "bundled" retail service in name only:  a so-
         called "buy-sell" transaction in which an end user arranges for
         the purchase of generation from a third-party supplier and a
         public utility transmits that energy in interstate commerce and
         re-sells it as part of a "bundled" retail sale to the end user.
         We have determined that in these types of transactions the retail
         "bundled" sale is actually the functional equivalent of two
         Docket Nos. RM95-8-000
           and RM94-7-001              -100-
         unbundled retail sales:  (1) a voluntary sale of unbundled
         transmission at retail in interstate commerce, subject to our
         exclusive jurisdiction; 187/ and (2) a sale of unbundled
         generation at retail, subject to the state's jurisdiction.
         188/  For these types of sales, public utilities will have to
         provide the voluntary retail transmission component of the sale
         under a FERC-filed tariff consistent with the substantive
         requirements of this proposed rule.
              We are aware that some public utilities are already
         contemplating initiating this type of "buy-sell" service.
         Similar services occurred in the natural gas area, but the
         Commission did not address the jurisdictional issue until a
         substantial number of transactions had been negotiated and
         implemented.  When the Commission ultimately addressed the
         natural gas buy-sell programs, we concluded that we have
         jurisdiction over buy-sell transactions since such agreements
         utilize interstate transportation. 189/  We were concerned
         then, just as we are concerned now, that interstate and
         intrastate programs operate together in an appropriately

         187/ As discussed infra, there would be a component of local
              distribution in such a transaction, subject to the state's
              jurisdiction.
         188/ This determination is consistent with our findings regarding
              similar types of transactions in the natural gas area.  See
              El Paso Natural Gas Company, 59 FERC ¶ 61,031 (1992),
              dismissed sub nom. Windward Energy and Marketing Company v.
              FERC, No. 92-1208 (D.C. Feb. 2, 1994).
         189/ Id.
         Docket Nos. RM95-8-000
           and RM94-7-001              -101-
         integrated way. 190/  It is our preliminary view that the
         interstate transmission aspect of the buy-sell program must take
         place under a FERC-filed tariff.
              In imposing this requirement we wish to stress that the
         state has jurisdiction to determine which group of retail
         customers may participate in such a program.  We also recognize
         that state regulatory commissions will be called upon to
         determine whether they have jurisdiction under state law over
         retail wheeling or direct access programs and, if so, whether to
         authorize such  programs. 191/  However, the rates, terms,
         and conditions for the interstate transmission aspects of the
         program are jurisdictional to this Commission.  
              The Commission did not address this jurisdictional issue at
         an early state in the evolution of competition in the natural gas
         market.  Consequently, when we finally acted we chose to
         grandfather ongoing programs so that energy supply arrangements
         would not be disrupted. 192/  We do not want to face that
         difficulty again.  Thus, we are addressing the issue at an early
         stage so that public utilities and their customers will be on

         190/ 56 FERC ¶ 61,289 at 62,133 (1991).
         191/ This Commission does not have authority to order retail
              wheeling.  Section 212(h) of the Federal Power Act, as
              amended by the Energy Policy Act of 1992, Pub. L. No. 102-
              486, 106 Stat. 2776.
         192/ 59 FERC ¶ 61,031 (1992); reh'g denied, 60 FERC ¶ 61,117
              (1992).
         Docket Nos. RM95-8-000
           and RM94-7-001              -102-
         notice of the jurisdictional implications of their actions, and
         can make plans accordingly.
                   3.   Real-time Information Networks
              With this proposed rule, the Commission is issuing a Notice
         of Technical Conference and Request for Comments on a proposal to
         require that public utilities provide all transmission users,
         including the transmission owner or controller, simultaneous
         access to transmission and ancillary services information through
         real-time information networks that would operate under industry-
         wide standards.  Based upon the lessons we have learned from our
         experience with gas pipeline EBBs, we believe the proposed
         approach is necessary and can work.  
                   4.  Non-discriminatory Open Access Tariff Provisions
              It is important that the tariffs filed to meet the non-
         discriminatory open access service requirement contain terms and
         conditions necessary to ensure a certain minimum level of service
         quality and to provide a level of certainty to both customers and
         transmission service providers as to procedures and obligations.
         The discussion in this section is intended to give guidance about
         our proposed non-discriminatory open access requirements.  The
         terms and conditions discussed here are reflected in the pro
         forma tariffs in Appendices B and C. 193/
              We note at the outset two basic principles proposed to be
         used when evaluating tariff terms.  First, the terms and

         193/ These Appendices will not appear in the Federal Register.
         Docket Nos. RM95-8-000
           and RM94-7-001              -103-
         conditions governing service should be clear and specific.  Vague
         or general tariff terms introduce uncertainty, controversy and
         delay.  In many situations, delaying access or increasing the
         transaction cost of access is, for all practical purposes,
         denying access.  Second, any restrictions or limitations on
         service or procedures must be limited to technical or operational
         needs that can be verified, and they must be the least
         restrictive way to meet those needs. 194/  
              The Commission invites comment on the terms and conditions
         proposed as well as whether others may be necessary.
                   a.  Customer eligibility.  A non-discriminatory open-
         access tariff must be available to any entity that can request
         transmission services under section 211. 195/     
                   b.  Expansion obligation.  A public utility must offer
         to enlarge its transmission capacity (or expand its ancillary
         service facilities) if necessary to provide transmission
         services.  This provision is necessary to mitigate the utility's
         transmission market power that could be exercised by restricting

         194/ However, as discussed infra, in determining the level of
              capacity that must be made available for new transmission
              service requests, we have proposed that capacity needed to
              meet current and reasonably forecasted native load and to
              meet existing contractual obligations may be excluded from
              capacity made available for new transmission service
              requests.
         195/ Under section 211, any electric utility, Federal power
              marketing agency, or any other person generating electric
              energy for sale for resale may request transmission services
              under section 211.
         Docket Nos. RM95-8-000
           and RM94-7-001              -104-
         capacity.  The customer must agree to reasonable terms,
         conditions and prices, including the financial responsibility for
         its share of the incremental expansion costs. 196/  
              The Commission recognizes that a utility may not be able to
         enlarge transmission capacity because it cannot obtain the
         necessary approvals or property rights under applicable Federal,
         state and local laws.  If the utility has failed after making and
         documenting a good faith effort to obtain the necessary approvals
         or property rights, it can request to be relieved of its
         expansion obligation by an appropriate filing at the Commission.
         197/  This will result in consistent treatment under FPA
         sections 205 and 206 and FPA section 211.
                   c.  Service obligation.  The transmission tariff must
         offer non-discriminatory transmission services (including related
         ancillary services that the utility can provide) to eligible
         transmission customers.  For example, a tariff should make
         available both flexible (i.e., firm and non-firm) point-to-point
         transmission service and network transmission service, as well as

         196/ See, e.g., Northeast Utilities Service Company, 56 FERC ¶
              61,269 at 62,022 (1991), order on reh'g, 58 FERC ¶ 61,070,
              reh'g denied, 59 FERC ¶ 61,042 (1992), remanded, 993 F.2d
              937 (1st Cir. 1993), order on remand, 66 FERC ¶ 61,332
              (1994) (Northeast Utilities) (wheeling customer must provide
              reasonable financial assurance before the public utility
              undertakes substantial investments in new facilities for
              that customer).
         197/ However, we have previously noted that a utility may bear a
              heavy burden in demonstrating that it cannot enlarge its
              transmission capacity to meet a new transmission request.
              See Northeast Utilities, 58 FERC at 61,209.
         Docket Nos. RM95-8-000
           and RM94-7-001              -105-
         those ancillary services necessary to accomplish such
         transmission services.  
                   (1)  Network Transmission Service.
              Network transmission service allows a transmission customer
         to use the entire transmission network to provide generation
         service for specified resources and specified loads without
         having to pay a separate charge for each resource-load pairing.
         Such service allows a transmission customer to integrate, plan,
         commit, economically dispatch, and regulate its resources to
         serve its consolidated load.  Network service provides the
         customer with the same flexible network usage needed to optimize
         its resources to meet its customers' needs that transmission
         owners have to optimize their resources to meet their customers'
         needs.  Network service includes the ability to import power from
         other control areas to economically and reliably serve the
         customers' load.  Non-discrimination requires that network
         service be made available in an open access tariff.
              Network service would be valuable to customers such as
         municipals, cooperatives, and municipal joint action agencies
         that supply the long-term firm power needs of members with
         multiple loads that are wholly or partly within a single
         transmission system.  Indeed, network service is essential for
         the resource integration that is needed for efficient operation.
         For example, a generation and transmission cooperative whose
         generating facilities and member cooperatives are widely
         Docket Nos. RM95-8-000
           and RM94-7-001              -106-
         dispersed may not own all of the transmission facilities needed
         to link the generators with the members' distribution systems.
         In this case, the cooperative must rely on a transmission-owning
         utility to provide network service.  Without such service, the
         cooperative would have difficulty supplying reliable, efficient
         power to its own members.
                   (2)  Flexible Point-to-Point Service
              The second required service in a non-discriminatory open
         access tariff is point-to-point transmission service.  Both firm
         and non-firm service must be available on a point-to-point basis.
         Under firm point-to-point service, the transmission owner would
         provide firm deliveries of power from designated points of
         receipt to designated points of delivery.  Each point of receipt
         would be set forth in a service agreement along with a
         corresponding capacity reservation for that point of receipt.
         Each point of delivery would be set forth in the service
         agreement along with a corresponding capacity reservation for
         that point of delivery.  The greater of (1) the sum of the
         capacity reservations at the point(s) of receipt, or (2) the sum
         of the capacity reservations at the point(s) of delivery would be
         the firm capacity reservation for which the transmission customer
         would be charged.
              However, firm point-to-point service must have the same
         flexibility in use as that available to the transmission provider
         and obligate the transmission provider to supply non-firm
         Docket Nos. RM95-8-000
           and RM94-7-001              -107-
         transmission service, if available, over non-designated receipt
         and delivery points (or over designated receipt and delivery
         points in excess of its firm reservation at those points) without
         incurring any additional charges (or executing a new service
         agreement) so long as the customer's use does not exceed its
         total firm capacity reservation.  Any use by a customer in excess
         of its firm capacity reservation at each point of receipt or
         point of delivery will be on an as-available basis and will be
         treated as non-firm service.  A customer may also request non-
         firm point-to-point transmission service on a stand-alone basis.
              Transmission customers may be willing to trade off the
         higher risk of interruption with non-firm service for the lower
         non-firm transmission rate.  Customers should be able to make
         that choice, which will depend on their own balancing of the risk
         of transmission service interruption with the interruptibility
         of, and trade gains associated with, the power resource.  It is
         important that the customer, not the transmission provider, make
         this choice.  The tariff should not restrict non-firm
         transmission service to the transporting of only non-firm power
         transactions. 198/    
              Tariffs should offer flexible point-to-point transmission
         service for transactions that involve power flows into, out of,

         198/ See Entergy Services, Inc., 58 FERC ¶ 61,234 at 61,767,
              order on reh'g, 60 FERC ¶ 61,168 (1992), rev'd on other
              grounds sub nom. Cajun Electric Power Cooperative, Inc. v.
              FERC, 28 F.3d 173 (D.C. Cir. 1994).
         Docket Nos. RM95-8-000
           and RM94-7-001              -108-
         within or through the control areas.  Whether or not a
         transmission provider actually undertakes such specific services
         on its own behalf, it has the flexibility to do so.  Therefore,
         if service to third parties is to be non-discriminatory, they,
         too, must have such flexibility.  In addition, tariff
         restrictions on receipt and delivery points should not preclude
         particular types of transactions.  For example, a transmission
         provider should not limit receipt and delivery points to points
         of interconnection with other transmission systems because such a
         restriction may preclude transactions that originate or terminate
         with generation or particular loads within a transmission
         provider's control area.
                   (3)  Ancillary Services
              Ancillary services are those services necessary to support
         the transmission of electric power from seller to purchaser given
         the obligations of control areas and transmitting utilities
         within those control areas to maintain reliable operations of the
         interconnected transmission system.  Basic transmission service
         without ancillary services may be of little or no value to
         prospective customers.  A variety of ancillary services is needed
         in conjunction with providing basic transmission service to a
         customer.  These services range from actions taken to effect the
         transaction (such as scheduling and dispatching services) to
         services that are necessary to maintain the integrity of the
         transmission system (such as load following, reactive power
         Docket Nos. RM95-8-000
           and RM94-7-001              -109-
         support, and system protection services).  Other ancillary
         services are needed to correct for the effects associated with
         undertaking a transaction (such as loss compensation and energy
         imbalance services).  Due to the nature of certain ancillary
         services (such as scheduling and dispatching service), the
         transmission provider may be uniquely positioned to provide these
         services.  However, for other ancillary services (such as loss
         compensation service), the customer may wish to provide the
         service itself or purchase the service from a party other than
         the transmission owner or its agent.
              If the transmission provider provides the ancillary services
         for its own use of the transmission system, the public utility
         should offer in the tariff to provide ancillary services for
         transmission customers.  Tariffs should commit to provide
         specific ancillary services at specific prices or under specific
         compensation methods that are clearly described.  
              If the transmission provider obtains ancillary services from
         a third party, e.g., does not operate its own control area or
         obtains ancillary services from a pool, the transmission provider
         should offer in the tariff to secure ancillary services for
         transmission customers from that third party.  Examples of such
         third-party arrangements may include a public utility obtaining
         ancillary services from a power pool or from a control area
         operator.
         Docket Nos. RM95-8-000
           and RM94-7-001              -110-
              Based on our experience to date, we propose that the
         following ancillary services should be offered in the tariff:
                   1.  Reactive Power/Voltage Control Service
              In order to maintain transmission voltages on the
         transmission provider's transmission facilities within acceptable
         limits, transmission facilities and some or all generation
         facilities (in the service area where the transmission provider's
         transmission facilities are located) are operated to produce (or
         absorb) reactive power.  Thus, the need for reactive
         power/voltage control service must be considered for each
         transaction on the transmission provider's transmission
         facilities.  The amount of reactive power/voltage control service
         that must be supplied with respect to the transmission customer's
         transaction will be determined based on the reactive power
         support necessary to maintain transmission voltages within limits
         that are generally accepted in the region and consistently
         adhered to by the transmission provider.
              The transmission provider will be responsible for providing
         the necessary transmission-related reactive power support.  A
         transmission customer may elect (or arrange through a third
         party) to supply some or all of the necessary generation-related
         reactive power/voltage control support to the extent that it (or
         the third party) has the ability to supply such reactive power.
         If the transmission customer elects (or arranges through a third
         party) to provide reactive power/voltage control support, such
         Docket Nos. RM95-8-000
           and RM94-7-001              -111-
         service must be coordinated with the transmission provider (or
         the entity that is responsible for the operation of the
         transmission provider's transmission facilities).  Alternatively,
         the transmission provider will supply the necessary generation-
         related reactive power/voltage control support.
                   2.  Loss Compensation Service
              Capacity and energy losses occur when a transmission
         provider delivers electricity across its transmission facilities
         for a transmission customer.  A transmission customer may elect
         to (1) supply the capacity and/or energy necessary to compensate
         the transmission provider for such losses, (2) receive an amount
         of electricity at delivery points that is reduced by the amount
         of losses incurred by the transmission provider, or (3) have the
         transmission provider supply the capacity and/or energy necessary
         to compensate for such losses.
                   3.  Scheduling and Dispatching Services
              Scheduling is the control room procedure to establish a pre-
         determined (before-the-fact) use of generation resources and
         transmission facilities to meet anticipated load (including
         interchange).  Dispatching is the control room operation of all
         generation resources and transmission facilities on a real-time
         basis to meet load within the transmission provider's designated
         service area (or other larger area of coordinated dispatch
         operation).  Scheduling and dispatching services are to be
         provided by the transmission provider or other entity that
         Docket Nos. RM95-8-000
           and RM94-7-001              -112-
         performs scheduling and dispatching for the transmission
         provider's service territory.
              In certain regions, dynamic scheduling is also allowed.
         Dynamic scheduling involves responding to load changes or
         controlling generation within one transmission provider's service
         territory (or other larger area of coordinated dispatch
         operation) through the real-time control and dispatch of another
         transmission provider.  Under dynamic scheduling, the operator of
         an area of coordinated dispatch (control area) agrees to assign
         certain customer load or generation to another area of
         coordinated dispatch, and to send the associated control signals
         to the respective control center of that area.  Dynamic
         scheduling is implemented through the use of special telemetry
         and control equipment.  The transmission customer must be allowed
         to use dynamic scheduling when it is feasible and reliable.
                   4.  Load Following Service
              Load following service is necessary to provide for the
         continuous balancing of resources (generation and interchange)
         with load under the control of the transmission provider (or
         other entity that performs this function for the transmission
         provider).  Load following service is accomplished by increasing
         or decreasing the output of on-line generation (predominantly
         through the use of automatic generating control equipment) to
         match moment-to-moment load changes.  The obligation to maintain
         this balance between resources and load lies with the
         Docket Nos. RM95-8-000
           and RM94-7-001              -113-
         transmission provider (or other entity that performs this
         function for the transmission provider).  Because of the nature
         of this service, the transmission provider (or other entity that
         performs this function for the transmission provider's
         facilities) may be uniquely positioned to provide load following
         service.  Therefore, unless the  transmission customer is able to
         obtain such service from its own generation or from third-party
         generation that is capable of supplying such service in
         accordance with conditions generally accepted in the region and
         consistently adhered to by the transmission provider, the
         transmission provider will supply load following service.
                   5.  System Protection Service
              A transmission provider must have adequate operating
         reserves or other system protection facilities available in order
         to maintain the integrity of its transmission facilities in the
         event of (1) unscheduled outages of a portion of its transmission
         facilities or facilities connected to the transmission provider's
         service territory or (2) unscheduled interruption of energy
         deliveries to the transmission provider's transmission
         facilities.  The amount of system protection service that must be
         supplied with respect to the transmission customer's transaction
         will be determined based on operating reserve margins or other
         relevant criteria that are generally accepted in the region and
         consistently adhered to by the transmission provider.
         Docket Nos. RM95-8-000
           and RM94-7-001              -114-
              The transmission customer may elect or arrange through a
         third party to provide resources that are sufficient to satisfy
         the system protection needs of the transmission provider.
         Operation and dispatch of such resources must be coordinated with
         the transmission provider or other entity that maintains
         operating reserves and other system protection facilities for the
         transmission provider's service territory.  
                   6.  Energy Imbalance Service
              Energy Imbalance Service is provided when a difference
         occurs between the hourly scheduled amount and the hourly metered
         (actual delivered) amount associated with a transaction.
         Typically, an energy imbalance is eliminated during a future
         period by returning energy in-kind under conditions similar to
         those when the initial energy was delivered.  
              The transmission provider shall establish a deviation band
         (e.g., +/- 1.5 percent of the scheduled transaction) to be
         applied hourly to any energy imbalance that occurs as a result of
         the transmission customer's scheduled transaction(s).  Parties
         should attempt to eliminate energy imbalances within the limits
         of the deviation band within 30 days or a reasonable period of
         time that is generally accepted in the region and consistently
         adhered to by the transmission provider.  If an energy imbalance
         is not corrected within 30 days or a reasonable period of time
         that is generally accepted in the region and consistently adhered
         to by the transmission provider, the transmission customer will
         Docket Nos. RM95-8-000
           and RM94-7-001              -115-
         compensate the transmission provider for such service.  Energy
         imbalances outside the deviation band will be subject to charges
         to be specified by the transmission provider.  To the extent
         another entity performs this service for the transmission
         provider, charges to the transmission customer are to reflect
         only a pass-through of the costs charged to the transmission
         provider by that entity.
              We seek comment on our proposed treatment of ancillary
         services.  Are there alternative ways to ensure the non-
         discriminatory provision of ancillary services?  We also seek
         comment on the above-described ancillary services.  Are they the
         appropriate ancillary services for the needs of entities seeking
         transmission service?  Are the descriptions of the ancillary
         services appropriate?  Should any of the described services not
         be offered, and if so, why?  Are there other ancillary services
         that should be offered?  Should all ancillary services be offered
         as discrete services with separate prices, or should certain
         ancillary services be offered as a package?  Additionally, we
         seek comment on whether the additional complexity of obtaining
         ancillary service externally from the host control area with the
         use of dynamic scheduling is the appropriate course to follow.
                   d.  Service Periods.  The duration of  service
         reservations should not be unduly limited.  Non-discriminatory
         service requires any such limits on third-party service to be the
         same as those the transmission provider or controller faces.  In
         Docket Nos. RM95-8-000
           and RM94-7-001              -116-
         particular, the tariff should allow firm service contracts to
         extend at least for the life of a customer's power plant or
         purchase contract.  Power developers are unlikely to build new
         plants if they cannot secure firm transmission services for the
         plant's life.  Integrated transmission owners plan their
         transmission systems to ensure capacity to deliver the output of
         their own planned generation units.  Non-discriminatory service
         requires the same for transmission-only customers.  Likewise, the
         minimum duration for service should be the same as the minimum
         scheduling period of the transmission owner.  All minimum or
         maximum restrictions must be justified on a technical or
         operational basis.   
                   e.  Reassignment Rights.  A tariff must explicitly
         permit reassignment of firm service entitlements.  Capacity
         reassignment rights can have a number of benefits.  First,
         reassignment rights are important in helping transmission users
         manage the financial risk associated with long-term commitments
         to take transmission service.  A robust reassignment market would
         aid, among others, customers who can get or must take
         transmission capacity now but do not actually need it until some
         time in the future, and customers whose need for capacity they
         have under contract is intermittent or suddenly declines.
         Transmission owners have the flexibility to manage this sort of
         risk by offering transmission capacity to others.  Non-
         discriminatory service demands that non-owner holders of rights
         Docket Nos. RM95-8-000
           and RM94-7-001              -117-
         to transmission capacity have the same flexibility to manage
         their risk as owners have.
              Second, capacity reassignment, combined with assured access
         to firm transmission service, reduces the transmission provider's
         market power by enabling transmission customers to compete with
         the owner to some extent in the firm transmission market.  To
         promote competition in such a secondary market, firm service
         rights should be defined as broadly as possible, consistent with
         reliable operation of the system.  In particular, using firm
         transmission capacity to deliver non-firm power or repackaging
         firm transmission capacity for sale as non-firm capacity should
         not be unduly restricted.
              Third, the ability to reassign capacity rights can also
         improve capacity allocation.  When capacity is constrained and
         some market participants value capacity more than current
         capacity holders, the current holders may be willing to reassign
         their capacity rights at rates below the opportunity costs of the
         transmission provider, thereby lowering rates to the new
         customer.  We note that the prices of reassignments are currently
         capped at the price the public utility sold the transmission.
         199/  The Commission invites comments on whether the current

         199/ See Florida Power & Light Company, 66 FERC ¶ 61,227 at
              61,524 (1994), order on reh'g, 70 FERC ¶ 61,150 (1995).  The
              Commission has required a similar cap for released pipeline
              capacity.  See Order No. 636-A, Pipeline Service Obligations
              and Revisions to Regulations Governing Self-Implementing
              Transportation Under Part 284 of the Commission's
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001              -118-
         price cap on resale should be modified or eliminated.   
              In addition, the service agreement must state clearly the
         respective obligations of the original right holder and any
         subsequent purchaser of the right.  In particular, it should
         state the conditions, if any, under which the original right
         holder can be released from its obligations under the service
         agreement if the right is reassigned or sold.  Any reassignments
         must be done in a not unduly discriminatory manner.  We invite
         comment on these reassignment issues.
              Given the current specification of basic transmission
         services (network, flexible point-to-point, and ancillary), some
         services may be more reassignable than others.  The ease with
         which rights can be reassigned depends on two factors:  the
         ability of ensuring operational feasibility and the specificity
         of contract rights.  Point-to-point service involves a well-
         specified right to transfer a given amount of power between
         specific points or across an interface under certain conditions.
         The transmission provider is operationally indifferent as to who
         wants to transfer the power that flows between those points.
         Thus, point-to-point service is well-suited to reassignment.

         199/(...continued)
              Regulations, Regulation of Natural Gas Pipelines After
              Partial Wellhead Decontrol and Order Denying Rehearing in
              Part, Granting Rehearing in Part, and Clarifying Order No.
              636, Ferc Stats. & Regs. ¶ 30,950 at 30,560 (1992), appeal
              pending.
         Docket Nos. RM95-8-000
           and RM94-7-001              -119-
              Network service, as currently defined, is idiosyncratic
         because it is unique to the transmission user receiving the
         service.  This service is purchased to integrate a set of
         resources into a set of loads given specific dispatch parameters
         and load profiles.  The transmission provider has to plan and
         operate its system for this specific service.  It is not clear
         that such service could be of any value to an entity other than
         the original buyer.  It is also not clear precisely what would be
         resold because network customers do not have rights to a specific
         amount of transmission capacity, but have rights only to a
         varying amount of capacity needed to integrate load with their
         dispersed power resources. 200/  Such indeterminate rights
         may not be amenable to reassignment.  We seek comments on
         reassigning network service.  Can network service be structured
         such that capacity rights could be specified and reassigned?
              Ancillary services also may not be suitable for
         reassignment.  We seek comments on these reassignment issues.  
                   e.  Reciprocity provision.  The Commission proposes to
         require that transmission tariffs contain a reciprocity
         provision. 201/  The purpose of this provision is to ensure

         200/ In FP&L, the Commission approved network service billing
              based on a load ratio method of cost allocation, instead of
              on contract demand.
         201/ The Commission previously accepted tariffs that contain
              reciprocity provisions.  See, e.g., El Paso Electric Company
              and Central and South West Services Inc., 68 FERC ¶ 61,181
              at 61,916 (1994), reh'g pending; Southwestern Electric Power
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001              -120-
         that a public utility offering transmission access to others can
         obtain similar service from its transmission customers.  It is
         important that public utilities that are required to have on file
         tariffs be able to obtain service from transmitting utilities
         that are not public utilities, such as municipal power
         authorities or the federal power marketing administrations that
         receive transmission service under a public utility's tariff.  
                   f.  Available Transmission Capacity (ATC).  ATC is
         capacity that must be made available for new firm transmission
         service requests.  Basically, it is the capacity not committed to
         other firm uses during the scheduling interval(s) for which
         service is requested.  The tariff must clearly specify the other
         uses for which capacity will be excluded from ATC.  Acceptable
         other uses may include:
              ⋅    A requirement to meet generally applicable reliability
                   criteria.
              ⋅    Meeting current and reasonably forecasted  load (retail
                   customers and network transmission customers) on the
                   transmission provider's system.  The term "reasonably
                   forecasted" should be defined in terms of the utility's
                   current planning horizon.  Capacity needed to serve
                   reasonably forecasted load must be made available until

         201/(...continued)
              Company and Public Service Company of Oklahoma, 65 FERC ¶
              61,212 at 61,981-82 (1993), reh'g denied, 66 FERC ¶ 61,099
              (1994).
         Docket Nos. RM95-8-000
           and RM94-7-001              -121-
                   the forecasted load develops.  
              ⋅    Fulfilling the transmission provider's current firm
                   power and firm transmission contracts.
              ⋅    Meeting pending firm transmission service requests.
              In the tariff, the utility must commit to provide an index
         of other holders of firm transmission entitlements and describe
         the method used to estimate ATC in sufficient detail to allow
         others to do the same analysis.  The utility must make all data
         used in calculating the ATC publicly available.  The methodology
         and the data used to develop the ATC must be consistent with the
         information submitted in the FERC Form No. 715, Annual
         Transmission Planning and Evaluation Report. 202/
              Capacity can be withheld from ATC only if it is to be used
         during the scheduling period for which service is requested.  For
         example, if a customer requests firm service for ten years and
         the utility needs that capacity to serve native load during years
         six to ten, the utility must provide service using the existing
         capacity for the first five years and then use expanded capacity
         or some other alternative arrangement for the third-party service
         during the remainder of the term.
              Under the proposed rule, ATC information will be required to
         be made available in the public utility's information system.
         The nature of the ATC information to be made available and the
         manner in which it is made available will be the subject of the

         202/ See Order Nos. 558 and 558-A, supra note 92.
         Docket Nos. RM95-8-000
           and RM94-7-001              -122-
         real-time information networks technical conference that we are
         concurrently initiating.
                        g.  Procedures for obtaining service.  This
         section must clearly describe all notice and response require-
         ments, including deadlines for each step in the process, the
         information required in a valid request for service, the
         procedure for obtaining service from existing capacity and the
         additional steps to follow when capacity expansion is required.
         The discussion below highlights some particularly important
         aspects of procedures for obtaining service.
              The tariff must specify minimum notice periods.  Notice for
         accepting requests for short-term service is particularly
         important.  Because market opportunities may be short-lived, the
         advance notice required for short-term service should be as brief
         as possible and should be able to be secured through the real-
         time information network.  Similarly, the tariff also should
         specify the minimum time needed to accommodate customers' needs
         to plan and construct new generating units or to enter into long-
         term power supply contracts.  
              A tariff must specify the information that must accompany a
         service request.  This information should generally track that
         specified in the Commission's Policy Statement Regarding Good
         Faith Requests for Transmission Services.  203/  The tariff
         should require only information that is clearly necessary to

         203/ See supra note 91.
         Docket Nos. RM95-8-000
           and RM94-7-001              -123-
         determine whether capacity is available, the price for the
         service requested and other information necessary to process the
         service request.
              A tariff may require scheduling of receipt and delivery
         points and amounts of energy flows but not require disclosure of
         power contract terms as part of the request process.  While the
         Commission has accepted such a requirement in some tariffs, our
         preliminary view is that there are less intrusive and less
         ambiguous ways of dealing with transmission owner concerns.  If
         the concern is the need to know intended power flows, the needed
         information of the anticipated transaction can be specified in a
         service request.  
              The concern may be that a customer will reserve scarce
         capacity and then hold it without using it (for whatever reason).
         While reservation holders as well as transmission providers
         should not be allowed to withhold capacity, there are less
         restrictive options for dealing with this concern.  One is to
         allow the transmission provider to use or sell the capacity for
         so long as the reservation holder is not using it.  Another is to
         have a pool that clears the short-term market.  Of course, the
         reservation holder would be compensated.  Another option is to
         require the customer to begin using the capacity within some
         period or lose its reservation rights for that capacity.  Any of
         these alternatives can allay legitimate concerns without forcing
         customers to reveal unnecessary details of the transaction.  The
         Docket Nos. RM95-8-000
           and RM94-7-001              -124-
         Commission requests comments on these and other approaches.
         Could pooling help address these issues?  In particular, how
         would a use-it-or-lose-it rule work?  How would a utility know
         which reservation holder to compensate with non-firm revenues if
         network service customers hold no reservation rights?  Non-firm
         revenues could be shared among load-ratio customers and
         reservation customers on the basis of the non-use of the firm
         entitlements.  
              With respect to network service, our preliminary view is
         somewhat different.  Because network service is billed on a load
         ratio basis, customers would have the incentive to specify
         unlimited generation resources to be integrated into their load
         without any commensurate financial obligation.  The transmission
         provider would nevertheless have to plan its system to dispatch
         those resources.  Thus, network customers, when designating their
         network resources, must show that they own or have contracted for
         those resources.  We seek comment on this issue.  Are there
         alternative ways of dealing with this problem for network
         service?
              The tariff should provide that, if service can be provided
         using existing capacity, a service agreement will be tendered in
         time for the customer to execute it so that service can begin at
         the time requested.  The tariff should clearly state the
         applicable rates for service from existing capacity.  In
         addition, the tariff should contain provisions, as well as rates,
         Docket Nos. RM95-8-000
           and RM94-7-001              -125-
         for reserving capacity now for use at a later time.  Also, the
         tariff should contain a standardized service agreement that
         applies to all service provided from existing capacity.
              When existing capacity is not adequate to provide additional
         firm service, the tariff should require the transmission provider
         to prepare, if needed, an engineering study of options for
         expanding capacity, including the costs of each option, within a
         specified period.  The customer should be required to pay the
         reasonable costs of performing the study.  If the customer elects
         to take service after reviewing the engineering study and cost
         estimates, including supporting documentation, the transmission
         provider may require the customer to enter into a contract,
         provide a security deposit, and agree to take service at rates
         calculated in accordance with the pricing provisions of the
         tariff. 204/  The tariff should allow the customer to specify
         the contract term.
                   h.  Service Priority.  Service priority becomes
         important when capacity is constrained (i.e., demand exceeds
         supply).  This, in turn, has two aspects:  when new service
         requests are considered and when, after service has begun,
         interruptions are required.

         204/ See Entergy Services, Inc., 58 FERC ¶ 61,234 at 61,766 and
              61,768 (1992) (security deposit or some other form of
              assurance permitted; approval of provision requiring
              transmission customers to have "suitable interconnection
              agreement" with transmission-owning utility).
         Docket Nos. RM95-8-000
           and RM94-7-001              -126-
                        (1)  Considering new service requests.
              A tariff should specify a reasonable basis upon which
         service requests will be considered.  As long as transmission
         capacity is available for all requests, they can all be
         accommodated.  When capacity is short, however, the priority of
         requests is important because the determination as to which
         requests are met from existing capacity and which require
         expanded facilities will affect pricing.  However, firm service
         requests should always receive priority over non-firm service
         requests, and firm service requests from third-party transmission
         customers should have the same priority as new transmission
         services for the public utility's native load.  
              The industry currently operates under a contract rights
         regime whereby customers are given contract rights for a specific
         period at a set price.  Under this regime, requests are generally
         processed under a first-in-time rule.  Capacity is allocated in
         the order in which the requests were made.  If available
         transmission capacity is exhausted, a requester may be required
         to pay the incremental cost of relieving the constraint.
         Incremental cost could be either the redispatch cost of unloading
         a line or the cost of expanding capacity.  Thus, the position of
         the requester in the queue may affect price and possibly
         determine when service is provided.  Alternatively, all
         requesters during a given period could be treated as making one
         request for a large increment of capacity and pay the same
         Docket Nos. RM95-8-000
           and RM94-7-001              -127-
         average incremental cost.  We seek comments on appropriate ways
         to process requests.
                        (2)  Allocating interruptions.
              After service has begun, priority is important if capacity
         becomes unexpectedly constrained and service must be interrupted.
205/
         Contracts must spell out the obligations and priorities in
         dealing with operating and reliability procedures.  Priorities
         will affect the order in which services are interrupted.  A
         tariff must specify that firm transmission service always has
         priority over non-firm transmission service.  Non-discriminatory
         service requires that firm transmission customers have the same
         assurance of uninterrupted use of the grid, within their
         contractual commitments and obligations, as the transmission
         provider.  That is, the public utility's personnel who trade
         wholesale power should have the same firm transmission service as
         does a firm transmission customer.  Both have the same standing
         when the control area operator deals with emergencies.  That is,
         both must recognize that the operator is authorized to interrupt
         scheduled power transfers as needed in order to maintain
         reliability.  Operators must be allowed to maintain safe and
         reliable service on the overall system.

         205/ Of course, the utility always may curtail if necessary to
              maintain the reliability of the system.  For example, if a
              major transmission line fails, the utility may quickly have
              to interrupt transactions without regard to priority of
              service in order to stabilize the system.  Once the system
              is stabilized, however, the utility should allocate
              remaining capacity on the basis of contractual priorities.
         Docket Nos. RM95-8-000
           and RM94-7-001              -128-
              Generally, interruption of firm transmission service should
         occur only because of:  (1) emergencies or force majeure; or (2)
         the need to maintain overall reliability or to protect equipment
         as prescribed in industry operating guidelines.  The specific
         reasons for interruptions will have to be determined in
         accordance with the characteristics of each transmission
         provider's system.  The tariff should require the provider to
         notify all customers in a timely manner of any scheduled
         interruptions, while recognizing the right to take appropriate
         actions under operating procedures to deal with unscheduled
         emergency conditions.
                   i.  Security deposits and creditworthiness.  A tariff
         may require that a reasonable, returnable deposit accompany the
         request for service, and that the customer demonstrate basic
         creditworthiness.  A creditworthiness investigation (including a
         security deposit requirement) must be applied on a non-
         discriminatory basis.
                   j.  Short-term and interruptible service agreements.  A
         copy of standard transmission service agreements for short-term
         and interruptible transmission services must be included in the
         tariff in order to expedite service and limit the possibility of
         undue discrimination or other abuse.  The tariff must list all
         information needed from the customer.
                   k.  Dispute resolution.  The tariff must clearly set
         forth the steps to be followed to resolve disputes.  Procedures
         Docket Nos. RM95-8-000
           and RM94-7-001              -129-
         should be designed to resolve conflicts quickly.  This suggests
         the use of some type of alternative dispute resolution (ADR)
         process, such as mediation or arbitration.  ADR would be
         especially useful when the dispute is over response times,
         capacity additions, a highly technical matter, or any matter that
         applies, but does not extend, existing Commission policy.  The
         tariff should specify which types of disputes must go to ADR and
         which disputes must be taken directly to this Commission.
              A tariff should provide that capacity expansion proceed
         while cost disputes are pending, provided the customer agrees to
         pay the costs actually incurred and the rate ultimately
         determined by the Commission.  This is needed to minimize delays
         when the customer wants the service but disputes the cost.  Such
         a provision would require the transmission owner to proceed with
         whatever steps are necessary to provide service to the customer,
         as long as the customer agrees to furnish a deposit and state in
         writing that it will take service at the rates, terms and
         conditions that are ultimately found just and reasonable by the
         Commission, or to pay all out-of-pocket costs incurred in
         processing the request up to the date of cancellation of the
         request.
                   l.  Pricing.  Transmission pricing must be consistent
         with the Commission's Transmission Pricing Policy Statement.
         206/  We especially note that the transmission public utility

         206/ See supra note 124.
         Docket Nos. RM95-8-000
           and RM94-7-001              -130-
         must charge itself the same price for transmission services that
         it charges its third-party wholesale transmission customers.  
              5.  Pro Forma Tariffs
              Appendices B and C to this proposed rulemaking contain pro
         forma tariffs that contain the minimally acceptable terms and
         conditions of service for point-to-point and network transmission
         services.  They contain tariff language that assures acceptable
         levels of service quality for non-price terms and conditions.
         For the most part, we have avoided specifying pricing provisions.
         The pro forma tariff provisions would of course be subject to
         case specific scrutiny to ensure that services are provided on a
         non-discriminatory open access basis.  We seek comment on whether
         these tariffs provide a good basis for defining the minimum
         acceptable non-price terms and conditions of service.
              6.  Broader Use of Section 211
              The Commission intends to exercise its authority under
         sections 205 and 206, as described in this proposed rule, in a
         complementary manner with its authority under section 211.
         Requiring all public utilities to file non-discriminatory open
         access tariffs, as set forth in this NOPR, will not alone ensure
         competitive bulk power markets in all regions of the United
         States.  Many utilities providing transmission services are not
         public utilities subject to our full jurisdiction. 207/

         207/ For example, there are approximately 56 electric utilities
              operating control areas in the United States that are not
              public utilities.  
         Docket Nos. RM95-8-000
           and RM94-7-001              -131-
         Section 211, however, permits entities to seek open access to all
         transmission facilities, including those owned by non-public
         utilities.  Thus, to further eliminate unduly discriminatory
         practices in the industry, the proposed rule encourages the broad
         use of section 211.
              While the Commission cannot order transmission sua sponte
         under section 211, nothing in section 211 prohibits groups of
         qualified applicants from simultaneously or jointly filing
         applications for the same service. 208/  Such group or joint
         action would permit the Commission to order tariffs of broader
         applicability.  
              Moreover, sections 211 and 212 require that applicants
         specify only rates, terms, and conditions of service, not
         specific transactions.  Thus, applicants can file requests for
         tariffs to accommodate future, currently unspecified, short-
         notice transactions, similar to the type of tariff filed by many
         utilities seeking approval of market-based rates or mergers.
         209/
              Section 211 bars the Commission from ordering service that
         would unreasonably impair the continued reliability of electric

         208/ This assumes, of course, that all have made the requisite
              request to the transmitting utility 60 days prior to filing.
              FMPA, for example, filed on behalf of numerous Florida
              municipals in the FP&L section 211 case.  See Florida
              Municipal Power Agency v. Florida Power & Light Company, 65
              FERC ¶ 61,125 (1993).
         209/ See CSW, supra, 68 FERC at 61,916.
         Docket Nos. RM95-8-000
           and RM94-7-001              -132-
         systems affected by the order.  To meet this requirement, the
         transmission owner and the applicant (or the Commission if
         necessary) can craft provisions in the general tariffs discussed
         above to assure that service will comply with standard industry
         operating practices and, thus, not have an unreasonable impact on
         reliability.
              Finally, section 211 permits an opportunity for an
         evidentiary hearing. 210/  Section 211 does not preclude
         applicants from lodging the record from a section 205 undue
         discrimination case involving the same service, nor does it
         preclude the Commission from incorporating and relying on the
         record and findings in a section 205 proceeding if the section
         211 applicant, the transmitting utility, and the service
         requested are the same.  In sum, sections 211 and 212 provide the
         Commission and the electric industry a much broader means to
         attain wider transmission access than has been achieved so far.
         In this regard, the Commission invites comment on further avenues
         the Commission can pursue to facilitate and expedite 211
         applications.
              Section 211 also complements our section 205 and 206
         authority in that it allows customers to request unique services
         not available in the non-discriminatory open access tariff.
         While our objective in this proposed rule is to implement a very

         210/ Such a hearing is required only if there are material issues
              of fact in dispute.  See Citizens for Allegan County, Inc.
              v. FPC, 414 F.2d 1125, 1128 (D.C. Cir. 1969).
         Docket Nos. RM95-8-000
           and RM94-7-001              -133-
         broad service commitment in the non-discriminatory open access
         tariff, customers may have unique service needs that are not
         contemplated in the open access tariff.  
              7.  Status of Existing Contracts
              There are three general types of existing wholesale
         contracts that could be affected by the proposed rule:  (1)
         requirements and other firm service contracts under which
         customers take bundled transmission and generation services; (2)
         coordination contracts for purchases or sales of economy energy;
         and (3) transmission-only contracts.  The Commission believes
         that it can eliminate unduly discriminatory practices and achieve
         more competitive bulk power markets without abrogating existing
         contracts.  Accordingly, as discussed supra, we have proposed to
         apply the unbundling requirement only to transmission services
         under new requirements contracts and new coordination
         transactions.  In addition, although the open access tariffs must
         be open to all entities that could request transmission service
         under section 211, i.e., all non-sham wholesale purchasers, we
         are not proposing to abrogate any existing power or transmission
         contracts.  However, there may be situations in which it would be
         contrary to the public interest to allow existing wholesale power
         or transmission contracts to remain in effect.  Accordingly, we
         invite comment on whether it would be contrary to the public
         interest to allow all or some of the above types of existing
         contracts to remain in effect.
         Docket Nos. RM95-8-000
           and RM94-7-001              -134-
              8.  Effect of Proposed Rule on Commission's Criteria for     
                  Market-based Rates
              As stated above, one of the primary reasons for this
         rulemaking is to foster increased wholesale competition, in order
         to reduce prices for consumers.  Moreover, the increased
         competition allowed by non-discriminatory open access may allow
         lighthanded regulation of wholesale sales for many more
         transactions and perhaps throughout many regions.
              The Commission's standards for allowing market-based rates
         for wholesale power sales require an applicant and its affiliates
         to demonstrate that they lack or have mitigated market power in
         generation and transmission, that they cannot erect other
         barriers to entry, 211/ and that there is no affiliate abuse
         or reciprocal dealing.  In KCP&L, 212/ the Commission
         determined that it no longer needed to examine generation
         dominance in analyzing market-based rate proposals for sales from
         new generation facilities.  However, the Commission has continued
         to evaluate generation dominance in analyzing market-based rate
         proposals for sales from existing generation capacity. 213/

         211/ For applicants with transmission market power, the
              Commission has required the mitigation of such power through
              the filing of a non-discriminatory open access tariff.  The
              Commission also has examined an applicant's control over
              potential barriers to entry, e.g., ownership or control of
              sites for generation facilities, generation equipment, or
              pipelines for supplying fuel.
         212/ 67 FERC at 61,557.
         213/ See Entergy Services Inc., 58 FERC ¶ 61,234 at 61,755
              (1992).
         Docket Nos. RM95-8-000
           and RM94-7-001              -135-
              If this rulemaking achieves the Commission's goals, and
         competition fueled by open access increases in the wholesale bulk
         power markets to the extent we expect, the increased competition
         may reduce or even eliminate generation-related market power in
         the short-term market.  Increased wholesale competition could
         reduce the need for cost-based regulation of bulk power sales and
         allow broader use of market-based rates.  For example, more
         competitive markets may allow us at some point to drop the
         generation dominance standard for existing capacity.  We believe
         that the increased competition expected to result from this
         rulemaking may allow us to consider innovative approaches to
         authorizing market-based rates for generation.  One suggestion in
         this regard has been that the Commission ought to consider
         filings made pursuant to section 205 seeking authorization of
         market-based rates for all sellers in a defined region.  For
         example, such a region conceivably could be defined by the
         boundaries of an RTG, a power pool, a reliability council, or the
         less formal boundaries of an economic market.  However, before
         proceeding to consider this suggestion, or any other innovative
         proposal for dealing with market-based rates for existing
         wholesale generation, the Commission must address certain
         threshold questions.  Therefore, the Commission solicits comments
         on the following questions:
              (1)  Assuming that a final rule in this proceeding mandates
                   that all public utilities must file generally
                   applicable non-discriminatory open access tariffs,
                   would wholesale sellers of generation from existing
         Docket Nos. RM95-8-000
           and RM94-7-001              -136-
                   generating facilities still possess market power?
                   (a)  Can we eliminate our generation dominance standard
                   based on before-the-fact predictions of changes to come
                   from our rulemaking, or must we rely on after-the-fact
                   evidence of the changes that did occur?
              (2)  For purposes of assessing whether existing wholesale
                   generators still possess market power, how ought the
                   relevant market be defined in an open access
                   transmission environment?  To what extent do the
                   boundaries of a regional transmission group, a power
                   pool, or a reliability council lend themselves to being
                   used to define the relevant market in an open access
                   environment?  
              (3)  Should it be determined that, notwithstanding non-
                   discriminatory open access transmission, existing
                   generators still possess market power, can such market
                   power be mitigated effectively to permit market-based
                   rates for existing generation?  And, if so, what are
                   the Commission's options?  For example:
                   (a)  Ought the Commission rely on rules of conduct,
                        market mechanisms intended to ensure competition
                        in wholesale power sales (such as bidding
                        procedures) and monitoring as the means to curb
                        such market power; or
                   (b)  Ought the Commission rely on structural reforms as
                        the means to curb such market power?
              (4)  Once the Commission has determined how to define the
                   relevant market in an open access environment, ought
                   the Commission entertain requests that all wholesale
                   sellers within such a market be authorized to charge
                   market-based rates?
               9.  Effect of Proposed Rule on Regional Transmission Groups
              In the Commission's Policy Statement Regarding Regional
         Transmission Groups (RTGs) we expressed support for the
         development of voluntary transmission associations and encouraged
         their formation.  We believe that RTGs can speed the development
         of competitive markets, increase the efficiency of the operation
         Docket Nos. RM95-8-000
           and RM94-7-001              -137-
         of transmission systems, provide a framework for coordination of
         regional planning of the system and reduce the administrative
         burden on the Commission and on members of RTGs by providing for
         voluntary resolution of disputes.
              Since the issuance of the Policy Statement, the Commission
         has given conditional approval to the bylaws of two RTGs.
         214/  Both approvals were conditioned on the members agreeing
         to offer comparable transmission services at least to other
         members, through either individual transmission tariffs or a
         generic regional tariff.  For public utilities, that condition
         would be superseded by fulfillment of the requirements of the
         proposed rule.
              To the extent public utilities view the comparability
         requirement in our two RTG orders as a disincentive to joining an
         RTG, that disincentive would be mooted.  All such utilities will
         be required to file tariffs.  Moreover, we will continue to
         provide substantial latitude for innovative pricing proposals by
         an RTG, as indicated in the Transmission Pricing Policy
         Statement.
              Some transmission users might conclude that the availability
         of comparability tariffs makes membership in an RTG less
         necessary.  But, this conclusion would ignore the comparative
         benefit of a member having its needs planned for on a region-wide
         basis under an RTG instead of on a system-by-system basis.

         214/ See SWRTA and WRTA, supra.
         Docket Nos. RM95-8-000
           and RM94-7-001              -138-
         Coordination of planning that results in a more efficient system
         creates economies for both transmitting utilities and users.  
              Also, the reduction in administrative burden for all parties
         involved in an RTG would remain.  RTG members can work out their
         own disputes without incurring the substantial costs and delays
         involved in litigating at the Commission or in the courts.  This
         fact alone makes for more flexible and responsive markets and
         reduces costs.  Moreover, the Commission has stated its
         willingness to give deference to decisions resolved through RTG
         dispute resolution procedures.
              In short, RTGs are still a valuable tool in promoting
         wholesale competition and in achieving other Commission goals.
         RTGs are structures to reflect the interests of all of the grid's
         users, not just some.  RTGs allow for consensual solutions to
         local or regional issues, instead of solutions imposed by FERC.
         RTGs can function as regional laboratories for experimentation on
         transmission issues.  And, RTGs will provide a regional forum, a
         necessary predicate to regional cooperation.  The potential
         benefits of RTGs would in no way be undermined by the rules
         proposed in this Open Access NOPR.
              F.   Stranded Costs and Other Transition Costs
                   1.   Supplemental Notice of Proposed Rulemaking on
                        Stranded Costs by Public Utilities and
                        Transmitting Utilities
                        a.   Introduction
              The Commission's Open Access NOPR would impose significant
         Docket Nos. RM95-8-000
           and RM94-7-001              -139-
         new requirements on public utilities -- requirements that would
         help us to achieve the goal of robust competitive wholesale power
         markets, and that would result in a new way of doing business for
         utilities.  The Open Access NOPR would give a utility's
         historical wholesale customers enhanced opportunities to reach
         new suppliers and, therefore, would affect the way in which
         utilities traditionally have recovered costs.  We believe it is
         essential to address the transition issues associated with the
         move toward competition responsibly.  The most significant of
         these issues is stranded cost recovery.
              The recovery of legitimate and verifiable stranded costs is
         critical to the successful transition of the electric utility
         industry from a tightly regulated, cost-of-service industry to an
         open transmission access, competitively priced industry.  Public
         utilities have invested billions of dollars in facilities built
         under a regulatory regime in which they have been permitted to
         recover all prudently incurred costs, plus the opportunity to
         earn a reasonable rate of return on their investment. 215/
         At the wholesale level (and in some instances the retail level),
         they are now entering a regulatory era in which they will have to
         compete to supply electric service.  We believe that utilities
         should be allowed to recover the costs incurred under the old
         regulatory regime according to the expectations of cost recovery

         215/ Many also have committed millions of dollars to purchase
              power under long-term power supply contracts.
         Docket Nos. RM95-8-000
           and RM94-7-001              -140-
         established under that regime.  
              The primary goal of the Open Access NOPR is to promote
         competitive wholesale markets by assuring that all wholesale
         sellers of generation have the opportunity to compete on a fair
         basis and that all wholesale purchasers can reach alternative
         sellers.  Ultimately, this should result in lowering electricity
         prices for the Nation's consumers.  In the meantime, however, if
         a wholesale customer is able to leave its existing generation
         supplier to shop for power elsewhere, we do not believe the
         existing supplier's shareholders or its remaining customers
         should have to bear costs that were prudently incurred under the
         old regulatory system to serve the departing customer.
              We cannot successfully and fairly encourage the development
         of competitive wholesale markets as envisioned by the Open Access
         NOPR until we have made provision for electricity suppliers to
         seek recovery of existing uneconomic costs (primarily generation)
         which they already have incurred (i.e., those that could not earn
         a reasonable return in a competitive market).  Recovery of
         legitimate and verifiable transition costs will permit all
         sellers, including the utilities who prudently incurred these
         costs, to compete on a more equal footing in competitive bulk
         power markets.  In addition, while stranded cost recovery may
         delay some of the benefits of competitive bulk power markets for
         some customers, the Commission learned from its experience in the
         restructuring of the natural gas industry that these types of
         Docket Nos. RM95-8-000
           and RM94-7-001              -141-
         transition costs must be addressed at an early stage if we are to
         fulfill our regulatory responsibilities in moving to competitive
         markets. 216/
              The Commission believes that the approach proposed in the
         Stranded Cost NOPR issued on June 29, 1994 217/ should
         adequately cover most, if not all, costs that could be stranded
         in an environment where transmission access is more widely
         available, including the access environment that the Commission
         expects if the provisions of the Open Access NOPR are adopted.
         Some of the mechanisms proposed in the initial NOPR have been
         revised in this Supplemental NOPR to reflect submitted comments.
         In addition, there may be implementation or other issues raised
         by the open access requirements that were not contemplated when
         the Stranded Cost NOPR was originally proposed.  Accordingly, we
         are issuing a Supplemental Notice of Proposed Rulemaking on
         Stranded Costs.  In this Supplemental NOPR, we make preliminary
         determinations 218/ on certain issues and seek additional

         216/ See AGD, supra note 9, 824 F.2d at 1021-30.  However, our
              mechanisms for addressing stranded costs in the electric
              industry differ from those used in the gas industry for the
              reasons discussed below.
         217/ See supra note 5.
         218/ If we were not issuing the Open Access NOPR, we would be
              inclined to adopt a final rule on stranded costs at this
              time.  However, we are concerned that the Stranded Cost NOPR
              might not provide appropriate mechanisms to address
              transition costs that could result from the open access
              environment envisioned by this NOPR.  Accordingly, our
              findings here are interlocutory in nature, and rehearing
              does not lie.  
         Docket Nos. RM95-8-000
           and RM94-7-001              -142-
         comments limited to the new matters proposed in this document,
         including the proposed open access requirements.  We also propose
         to permit public utilities and transmitting utilities to seek
         recovery through transmission rates of stranded costs associated
         with a discrete set of existing wholesale requirements contracts.
                        b.   Summary of Major Preliminary Determinations
              In response to the June 29 Stranded Cost NOPR, the
         Commission received initial and/or reply comments from 128
         entities, representing a broad cross-section of parties that
         participate in, or are affected by, the electric utility
         industry. 219/  The Commission has carefully reviewed all of
         the comments, and made several preliminary determinations.
         First, we have determined that recovery of legitimate and
         verifiable stranded costs should be allowed, and that direct
         assignment of stranded costs to departing customers, as proposed
         in the Stranded Cost NOPR, is the appropriate method for
         recovery. 220/
              Second, with respect to stranded costs associated with new
         wholesale requirements contracts, 221/ we reaffirm our

         219/ A list of commenters is attached as Appendix D.
         220/ As discussed infra, section III.F.1.c(13), however, this
              does not foreclose case-specific proposals for dealing with
              stranded costs in the context of voluntary corporate
              restructuring proceedings.
         221/ For recovery of wholesale stranded costs, the proposed rule
              distinguishes between stranded costs associated with
              wholesale requirements contracts executed after July 11,
                                                            (continued...)
         Docket Nos. RM95-8-000
           and RM94-7-001              -143-
         proposal that a public utility may not seek recovery of such
         costs except in accordance with an exit fee or other explicit
         provision contained in the contract.  The public utility may seek
         recovery in accordance with the contract.  However, no public
         utility or transmitting utility may seek recovery of stranded
         costs associated with new requirements contracts through any
         transmission rate under section 205, 206 or 211. 222/
              Third, with respect to stranded costs associated with
         existing wholesale requirements contracts 223/ that are not
         renewed and that do not contain exit fees or other stranded cost
         provisions, if the seller can demonstrate that it had a

         221/(...continued)
              1994, the date the proposed rule was published in the
              Federal Register ("new" contracts) and stranded costs
              associated with wholesale requirements contracts executed on
              or before that date ("existing" contracts).  Stranded Cost
              NOPR at 32,860.
         222/ As we indicated in the Stranded Cost NOPR, if the seller
              under a new wholesale requirements contract is a
              transmitting utility subject to the Commission's
              jurisdiction under section 211 of the FPA, but not also a
              public utility subject to the Commission's section 205-206
              jurisdiction, there will be no Commission forum for
              addressing wholesale stranded costs associated with the new
              contract.  Such utilities will not be able to seek recovery
              of wholesale stranded costs associated with such new
              contracts through rates for transmission services ordered
              under section 211, and the Commission does not have
              jurisdiction over their power sales contracts.  Therefore,
              these utilities must address recovery of stranded costs
              through their new wholesale requirements contracts subject
              to the appropriate regulatory authority approval.  Stranded
              Cost NOPR at 32,860-61.
         223/ Existing wholesale power sales contracts are those contracts
              executed on or before July 11, 1994.  Stranded Cost NOPR at
              32,860, 32,881.
         Docket Nos. RM95-8-000
           and RM94-7-001              -144-
         reasonable expectation that the contract would be renewed and can
         meet other evidentiary criteria, we believe that stranded cost
         recovery should be allowed.  We encourage the parties to such
         contracts to attempt to negotiate a mutually agreeable stranded
         cost amendment.  We have determined, however, that the three-year
         negotiation period proposed in the initial Stranded Cost NOPR
         should be abandoned.  We propose instead that:  (1) a public
         utility or its customer under the contract may, at any time prior
         to the expiration of the contract, file a proposed stranded cost
         amendment to the contract under section 205 or section 206; or
         (2) a public utility may, at any time prior to the expiration of
         the contract, file a proposal to recover stranded costs through
         transmission rates for a departing customer. 224/ We believe
         it is in the public interest to permit public utilities to seek
         recovery of stranded costs associated with existing contracts
         that do not explicitly address stranded costs, and that they be
         permitted to do so either through transmission rates or through
         amendment to the existing power sales contracts.  However, for a

         224/ If the selling utility under the existing contract is a
              transmitting utility that is not also a public utility, its
              wholesale requirements contracts are not subject to this
              Commission's jurisdiction.  Nevertheless, we do encourage
              such a transmitting utility to attempt to negotiate a
              mutually agreeable stranded cost amendment with its
              customer.  In addition, we will allow such a transmitting
              utility to file a request to recover stranded costs in
              transmission rates under FPA sections 211-212.  However,
              such transmitting utility would be required to make the same
              evidentiary demonstration as that required of public
              utilities seeking extra-contractual stranded cost recovery.
         Docket Nos. RM95-8-000
           and RM94-7-001              -145-
         utility to be eligible for stranded cost recovery, it must meet
         the evidentiary demonstration required by this rule.
              In examining proposals to recover stranded costs, we propose
         to apply a "reasonable expectation" standard and a rebuttable
         presumption that if contracts contain notice provisions, the
         utility had no reasonable expectation of continuing to serve the
         customer beyond the term of the notice provision.  We further
         propose to retain the requirement in the initial Stranded Cost
         NOPR that utilities attempt to mitigate stranded costs.  In
         addition, we are proposing that public utilities be required to
         follow certain procedures specified herein that permit a customer
         to obtain advance notice of its maximum possible stranded cost
         exposure without mitigation. 225/
              Fourth, with respect to costs stranded as a result of retail
         wheeling, or as a result of wholesale wheeling obtained by a
         retail-turned-wholesale customer, the Stranded Cost NOPR explored
         the issue of whether we should assume some responsibility for
         addressing such costs.  The vast majority of those commenting on

         225/ The customer's maximum possible stranded cost exposure
              without mitigation would be the revenues that the utility
              would have received from the customer had the customer
              continued to take service from the utility.  This is the
              amount from which the competitive market value of the power
              that the customer would have purchased would be deducted to
              compute the amount of recoverable stranded costs (using the
              "revenues lost" approach for calculating stranded costs that
              this rule proposes to adopt (see section III.F.1.c(8)
              infra)).  The utility will be required to make every effort
              to mitigate the amount of the stranded cost charge.  See
              section III.F.1.c(9).
         Docket Nos. RM95-8-000
           and RM94-7-001              -146-
         our proposed rule urged us not to get involved or otherwise
         assume responsibility for those types of stranded costs, except
         in certain very limited circumstances.  At this juncture, we have
         concluded that it is appropriate to leave it to state regulatory
         authorities to assume the responsibility for any stranded costs
         occasioned by retail wheeling, except in the narrow circumstance
         in which the state regulatory authority does not have authority
         under state law, at the time retail wheeling is required, to
         address recovery of such costs.  The Commission holds the strong
         expectation that states will provide procedures for, and the full
         recovery of, legitimate and verifiable stranded costs.
              We also have determined that this Commission should be the
         primary forum for public utilities to seek recovery, through FERC
         jurisdictional transmission rates, of stranded costs resulting
         from wholesale wheeling for newly created wholesale customers who
         leave their franchised utility's supply system (e.g., through
         municipalization). 226/
              In deciding that states are the more appropriate entities to
         address stranded costs resulting from retail wheeling, we are
         relying on assurances from our state colleagues, as evidenced,
         for example, in NARUC's comments on the proposed rule, that they

         226/ Although the Commission's June 29 NOPR characterized these
              types of stranded costs as "retail" stranded costs, we
              believe they are more appropriately characterized as
              "wholesale" stranded costs, since it is not only state or
              local authority that permits the costs to be stranded, but
              also the availability of wholesale transmission that causes
              the costs to be stranded.
         Docket Nos. RM95-8-000
           and RM94-7-001              -147-
         will address and resolve this difficult issue.  We continue to be
         of the opinion that utilities are entitled, from both a legal and
         policy perspective, to an opportunity to recover their past
         prudently incurred costs, including costs incurred to serve
         retail customers who obtain retail wheeling in interstate
         commerce.  We emphasize that we will not allow states to use
         rates for transmission in interstate commerce as the vehicle for
         passing through any stranded costs resulting from retail
         wheeling, except in the narrow circumstance described.  Thus,
         these costs must be recovered in rates in a manner that does not
         involve "transmission of electric energy in interstate commerce"
         as that phrase is used in the FPA. 227/  This approach
         ensures that the wholesale market will not be burdened by retail
         costs.  It also ensures that one state will not be able to place
         costs stranded by its ordering of retail wheeling 228/ on
         customers in another state.  
              As discussed infra, we believe the states have a number of
         mechanisms to provide for recovery of retail stranded costs in
         retail rates.  One of those mechanisms is a surcharge to state-
         jurisdictional rates for local distribution.  Accordingly, we are
         proposing to define "facilities used in local distribution" under

         227/ See 16 U.S.C. § 824(c).
         228/ We do not address whether states have the lawful authority
              to order retail wheeling in interstate commerce.
         Docket Nos. RM95-8-000
           and RM94-7-001              -148-
         section 201(b) of the FPA. 229/  We believe states may impose
         retail stranded costs on facilities or services falling under
         this definition. 230/
              We set out our preliminary findings here for the limited
         purpose of reopening the comment period of the Stranded Cost NOPR
         as to whether the requirements proposed in the Open Access NOPR
         raise additional implementation or other issues pertaining to
         stranded cost recovery that were not addressed in the initial
         Stranded Cost NOPR and, if so, whether the mechanisms we propose
         based on our preliminary determinations are adequate to allow
         recovery of stranded costs.  Additional issues on which we seek
         comment are delineated below.
                        c.   The Proposed Regulations
                        (1)  Justification for Allowing Recovery of
                             Stranded Costs and Estimates of the Magnitude
                             of Stranded Costs
                             (a)  Comments
               Virtually all of the investor-owned utility commenters
         support the NOPR's basic assumption that stranded costs can be
         created when a customer switches suppliers.  Many commenters,

         229/ 16 U.S.C. § 824(b).
         230/ States may also use their jurisdiction over local
              distribution facilities to address potential "stranded
              benefits," e.g., environmental benefits associated with
              conservation, load management, and other demand side
              management (DSM) programs.  See NARUC Resolution on
              Competition, the Public Interest, and Potentially Stranded
              Benefits, November 16, 1994 (Appendix C to NARUC's
              comments).
         Docket Nos. RM95-8-000
           and RM94-7-001              -149-
         including Electric Generation Association and Public Power
         Council, applaud the Commission for timely "addressing the
         difficult and controversial stranded cost issue and for
         recognizing that this issue must be resolved in order for all
         parties to harvest fully the benefits of a competitive electric
         industry." 231/  Edison Electric Institute (EEI) strongly
         endorses the recovery of stranded costs.   
              A number of commenters, primarily representing customer
         groups, disagree that the risk that a utility could lose
         customers (and thereby incur stranded costs) is a new phenomenon
         created by regulatory and statutory initiatives that utilities
         could not anticipate.  These commenters argue that utilities have
         long been aware that they risk losing customers to competition
         and that utilities should have planned for this eventuality.
              In support of this argument, American Forest and Paper
         Association (American Forest) and others argue that utilities
         have known for some time that wholesale customers can -- and in
         the general course of business, in fact, do -- leave utilities'
         systems for other suppliers without being obligated to pay for
         stranded costs.  Several commenters also argue that Congress put
         the industry on notice through PURPA and then EPAct that
         utilities are at risk of losing customers as a result of the pro-

         231/ Electric Generation Association comments at 1.
         Docket Nos. RM95-8-000
           and RM94-7-001              -150-
         competitive provisions of these statutes.  Numerous parties
         232/ note that the courts and the Commission have, in various
         cases, provided notice that, as a result of competitive forces in
         the industry, utilities have had no reasonable expectation that
         customers will remain on their systems after contract expiration.
         Commenters cite, among other cases, the Supreme Court's 1973
         decision in Otter Tail 233/ (in which the Court held that the
         refusal to wheel power could place a utility at risk of antitrust
         liability), the Commission's 1968 decision in Village of Elbow
         Lake v. Otter Tail Power Company 234/ (in which utilities
         were alerted to the threat of municipalization), and the
         Commission's 1983 decision in Kentucky Utilities Co. 235/ (in
         which a notice of termination provision was deemed to constitute
         the extent of the utility's protection of its investment incurred
         to support the contract service).

         232/ E.g., American Public Power Association (APPA), Florida
              Municipal Power Agency, Michigan Municipal Cooperative Group
              and Wolverine Power Supply Cooperative (Florida and Michigan
              Municipals), the Illinois Commerce Commission (Illinois
              Commission), Electricity Consumers Resource Council, the
              American Iron and Steel Institute and the Chemical
              Manufacturers Association (Industrial Consumers), and TDU
              Customers.
         233/ See Otter Tail, supra note 15.
         234/ Village of Elbow Lake v. Otter Tail Power Company, 40 FPC
              1262 (1968).
         235/ Kentucky Utilities Co., Opinion No. 169, 23 FERC ¶ 61,317,
              aff'd on reh'g in relevant part, 25 FERC ¶ 61,205 (1983),
              reversed on other grounds, 766 F.2d 239 (6th Cir. 1985).
         Docket Nos. RM95-8-000
           and RM94-7-001              -151-
               Some commenters 236/ argue that the Stranded Cost NOPR
         incorrectly assumes the existence of a wholesale service
         obligation.  These commenters argue that the NOPR improperly
         assumes that a utility has had an obligation to serve a wholesale
         requirements customer beyond the term set forth in the contract
         unless the contract contained a notice of termination provision
         or other more explicit stranded cost provisions.  According to
         these commenters, the wholesale service obligation is purely
         contractual, and utilities could not reasonably have expected to
         continue to provide service after the expiration of a particular
         contract.
              Some state commissions (e.g., Illinois Commission) also find
         the NOPR's notion of wholesale stranded costs to be misplaced.
         These state commission commenters note that competition and
         notice provisions have existed for decades and that a customer
         leaving the system for another supplier is no different from a
         customer leaving due to an economic downturn (e.g., a plant
         closing or relocation).  Under the latter circumstance, they note
         that the costs are allocated among the remaining customers, or,
         in some instances, shareholders.  A number of other state

         236/ E.g., American Forest, Industrial Consumers, the Municipal
              Resale Service Customers of Ohio, and the Stranded Cost
              Order Opponent Parties (SCOOP).  SCOOP consists of Delaware
              Municipal Electric Corporation, Village of Freeport, New
              York, City of Jamestown, New York, Town of Massena, New
              York, Modesto Irrigation District, M-S-R Public Power
              Agency, City of Santa Clara, California, and Southern
              Maryland Electric Cooperative, Inc.
         Docket Nos. RM95-8-000
           and RM94-7-001              -152-
         commissions (e.g., Indiana Utility Regulatory Commission (Indiana
         Commission)) urge that stranded cost recovery exclude costs
         associated with normal business risk, such as poor planning,
         customer relocation, self-generation, or cogeneration.
              With regard to the magnitude of the level of total industry
         stranded costs, while estimates vary widely, most commenters
         agree that the level of potential wholesale stranded costs is
         small relative to that of retail stranded costs.  Several state
         commissions and customer groups (e.g., Florida Public Service
         Commission (Florida Commission), APPA, Industrial Consumers,
         Illinois Commission, and SCOOP) argue that the potential level of
         wholesale stranded costs is largely exaggerated.  For example,
         SCOOP claims that "[s]eparating out only the wholesale exposure
         to stranded costs, and critically analyzing the extent of that
         exposure, will permit the Commission to recognize that wholesale
         stranded costs are little more than the 'flea on the tail of the
         dog' and not the dog itself." 237/  Many of these commenters,
         including the Illinois Commission, note that wholesale stranded
         costs are likely to be minimal because wholesale requirements
         sales for major investor-owned utilities account for roughly 6
         percent of their total net energy generated and received.
         Furthermore, these commenters contend that it is ridiculous to
         suggest that all of the generation assets associated with serving
         this wholesale load suddenly would become stranded.  In fact,

         237/ SCOOP comments at 2.
         Docket Nos. RM95-8-000
           and RM94-7-001              -153-
         some commenters expect the investor-owned utilities with lower-
         cost generation to benefit from increased competition.
              Additionally, the Environmental Action Foundation
         (Environmental Action) notes that some industry estimates assume
         a zero asset (or salvage) value for any stranded assets.
         Environmental Action claims that this assumption grossly
         overestimates the claimed industry level of stranded costs by
         failing to recognize that a utility with a stranded generating
         asset will likely lower its power prices to market levels to
         mitigate the total level of stranded costs.  Accordingly,
         Environmental Action suggests that estimated levels of potential
         wholesale stranded costs may, in fact, be lower after accounting
         for costs recovered by the utility as a result of aggressively
         marketing any stranded generating assets.
              EEI indicates that, based on an informal survey of its
         members, the number of cases likely to be filed at the Commission
         seeking to recover stranded costs from wholesale requirements
         customers under existing contracts will be far less than those
         filed during restructuring of the natural gas pipeline industry.
         238/  However, EEI states that, while the number of filings
         may be relatively small, the dollar amounts and the significance
         to the parties are great.  EEI indicates that the magnitude of

         238/ For example, a number of utilities (e.g., Allegheny Power
              Service Corporation (Allegheny Power), Consumers Power
              Company, and Wisconsin Power & Light Company (Wisconsin
              Power)) indicate that their total potential wholesale
              exposure is minimal.
         Docket Nos. RM95-8-000
           and RM94-7-001              -154-
         potential wholesale and retail stranded cost liability to the
         industry is in the upper range of the NOPR's tens of billions of
         dollars to $200 billion estimate.   
                             (b)  Preliminary Findings
              The electric utility industry has billions of dollars
         invested in utility assets and contracts that, in today's
         markets, may become uneconomic. 239/  If wholesale or retail
         customers leave their utilities' systems without paying a share
         of these costs, the costs will become stranded unless they can be
         recovered either from the departing customers or other customers.
         These are very real costs that, as previously discussed, were
         incurred under a regulatory system that imposed an obligation to
         serve on utilities (an explicit obligation at retail and arguably
         an implicit obligation at wholesale) 240/ and also permits
         recovery of all prudently incurred costs.  Moreover, while we

         239/ As discussed in section III.C.2 supra, new generation
              facilities can produce power on the grid at a cost of 3 to 5
              cents per kWh, yet the costs for large plants constructed
              and installed over the last decade were typically in the
              range of 4 to 7 cents per kWh for coal plants and 9 to 15
              cents per kWh for nuclear plants.
         240/ The Commission has never determined whether there is an
              actual obligation in the FPA to serve requirements
              customers.  Construction Work In Progress, Order No. 474,
              III FERC Stats. & Regs. ¶ 30,751 at 30,718 (1987).  The
              Commission's regulations, however, do require a rate filing
              to terminate a jurisdictional contract.  18 C.F.R. § 35.15
              (1994).  Moreover, in a few cases, the Commission has
              required service beyond the contract term.  E.g., Tapoco,
              Inc., et al., 39 FERC ¶ 61,363 (1987); Florida Power & Light
              Company, 8 FERC ¶ 61,121, reh'g denied, 9 FERC ¶ 61,015
              (1979)).
         Docket Nos. RM95-8-000
           and RM94-7-001              -155-
         recognize that there has always been some risk of a utility
         losing a customer, that risk has been greatly increased by
         significant statutory, regulatory, technological, and structural
         changes, including this rule, that utilities may not have
         reasonably foreseen at the time their investments were made.
              As discussed in the introduction of this document, the
         wholesale bulk power segment of the electric industry is
         undergoing a fundamental transformation from a monopolistic
         industry regulated on a cost-of-service basis to an open access,
         competitively priced industry.  The transformation will
         accelerate if the Commission adopts the open access transmission
         requirements it is proposing in Docket No. RM95-8-000.  We do not
         believe that utilities that made large capital expenditures or
         long-term contractual commitments to buy power many years ago
         should now be held  responsible for failing to foresee such
         fundamental changes in the industry.  The Commission will not
         ignore the effects of regulatory and statutory changes on the
         past investment decisions of utilities.  We believe that equity
         requires that utilities have an opportunity to recover legitimate
         and verifiable stranded costs associated with the development of
         competitive wholesale markets.
              This belief is bolstered by our experience during the
         restructuring of the natural gas industry.  During the 1980s and
         early 1990s, the Commission undertook a series of actions that
         eventually led to the restructuring of the gas pipeline industry.
         Docket Nos. RM95-8-000
           and RM94-7-001              -156-
         The restructuring of the industry and the introduction of
         competitive forces in the gas supply market left many pipelines
         holding uneconomic take-or-pay contracts with gas
         producers. 241/
              In Order No. 436, the Commission declined to take direct
         action to alleviate the burden that the uneconomic take-or-pay
         contracts placed on pipelines.  The Commission based its decision
         on a number of considerations, including its concern "regarding
         the ability of private parties in the gas production industry to
         rely on private contracts as a tool for structuring basic
         economic relationships." 242/
              However, in AGD, the U.S. Court of Appeals for the District
         of Columbia Circuit noted that the pipelines were "caught in an
         unusual transition" as a result of regulatory changes beyond the
         pipelines' control. 243/  The court faulted the Commission
         for failing to take direct action to address the effect of such
         regulatory changes on the uneconomic take-or-pay contracts.
         244/

         241/ The costs of gas supply contracts in the gas industry can be
              viewed as somewhat analogous to the costs of generation
              resources in the electric industry.
         242/ Order No. 436, supra note 12 at 31,492-93; see also AGD,
              supra note 9, 824 F.2d at 1026.
         243/ 824 F.2d at 1027.
         244/ Id. at 1021.
         Docket Nos. RM95-8-000
           and RM94-7-001              -157-
              The Court's reasoning in AGD concerning the restructuring of
         the gas industry is also applicable to the current move to
         competitive bulk power markets in the electric industry.  Once
         again, a regulated industry is faced with an "unusual transition"
         to a more competitive market.  Once again, one result of the
         transition is the possibility that utilities will be left with
         large unrecoverable costs.  In these circumstances, we believe
         that we must directly address the costs of the transition to a
         competitive industry by allowing utilities to recover their
         legitimate and verifiable stranded costs, and that we must do so
         simultaneously with any final rule we adopt concerning open
         access transmission.
                        (2)  The D.C. Circuit Court of Appeals Decision in
                             Cajun Electric Power Cooperative, Inc. v.
                             FERC
              In the Cajun case, 245/ the D.C. Circuit found that the
         Commission should have held an evidentiary hearing to determine
         whether the recovery of stranded investment costs, as permitted
         in an open access transmission tariff approved by the Commission,
         was anticompetitive and would preclude mitigation of Entergy
         Corporation's (Entergy) market power.  The transmission tariff
         under review in that case was intended to mitigate Entergy's

         245/ Cajun Electric Power Cooperative, Inc. v. FERC, 28 F.3d 173
              (D.C. Cir. 1994) (Cajun).
         Docket Nos. RM95-8-000
           and RM94-7-001              -158-
         market power by providing open access to its transmission system.
246/
         The open access transmission tariff provided that Entergy's
         subsidiaries could seek to recover their stranded investments
         from a departing generation customer by including in the
         departing customer's transmission rate the cost of Entergy's
         generation capacity that was stranded when the former customer
         switched suppliers.  The court expressed concern that this
         provision might constitute a tying arrangement whose purpose is
         to "cabin" Entergy's market power, stating:  "if a company can
         charge a former customer for the fixed costs of its product
         whether or not the customer wants that product, and can tie this
         cost to the delivery of a bottleneck monopoly product that the
         customer must purchase, the products are as effectively tied as
         they would be in a traditional tying arrangement." 247/
              The court noted that central to the Commission's approval of
         Entergy's open access transmission tariff was the Commission's
         finding that Entergy's market power would be mitigated upon the

         246/ The two other electric power tariffs under review in that
              case provided for the sale of wholesale power by various
              Entergy public utility subsidiaries at negotiated, market-
              based rates.  As the court indicated, these tariffs, in
              combination with the open access transmission tariff, "were
              designed to permit Entergy -- a monopolist of transmission
              services in the relevant market -- to engage in market-based
              pricing in the generation market, while simultaneously
              introducing competition to that market through the
              unbundling of generation sales from transmission services."
              Id. at 175.
         247/ Id. at 178.
         Docket Nos. RM95-8-000
           and RM94-7-001              -159-
         implementation of the tariff. 248/  However, the court
         suggested that permitting a transmission monopolist such as
         Entergy to impose generation-related charges on competitors who
         only seek transmission services might serve to increase, not
         mitigate, Entergy's market power because "Entergy can compete for
         generation sales outside its transmission grid without concern
         for a stranded investment charge [but] Entergy's competitors
         cannot compete for the customers on its transmission system on
         the same basis." 249/  Thus, the court held that "[t]he
         Commission must address whether the [transmission tariff's]
         provision of a process for recovery of stranded investment costs
         . . . precludes genuine open access to Entergy's transmission
         system.  In short, the question that must be asked now is whether
         the [transmission tariff] allows for 'meaningful access to
         alternative suppliers.'" 250/  The court went on to identify
         other provisions of the transmission tariff (in addition to the
         stranded cost provision) that might lessen the mitigation of
         Entergy's market power, including Entergy's retention of sole
         discretion to determine the amount of transmission capability

         248/ The court noted that although the Commission suggested that
              the stranded investment provision is necessary to lure
              Entergy into competition and provides an equitable recovery
              of costs from the parties for whom the costs were incurred,
              this is irrelevant if the Entergy tariffs do not
              sufficiently mitigate Entergy's market power.  Id. at 180.
         249/ Id.
         250/ Id. at 179 (emphasis in original).
         Docket Nos. RM95-8-000
           and RM94-7-001              -160-
         available for its competitors' use; the point-to-point service
         limitation; the failure to impose reasonable time limits on
         Entergy's response to requests for transmission service; and
         Entergy's reservation of the right to cancel service in certain
         instances even where a customer has paid for transmission system
         modifications. 251/  
              The court concluded that the transmission tariff as a whole
         "seems to provide Entergy with the means to stifle the very
         competition it purports to create." 252/  The court
         determined that the Commission erred in approving Entergy's
         tariffs without conducting hearings on whether, notwithstanding
         the purpose of the transmission tariff to mitigate market power,
         Entergy might retain market power.  Significantly, however, the
         court did not hold that stranded cost recovery could not be
         justified; its objection was to the Commission's procedures in
         that particular case and lack of explanation for its substantive
         decision to approve the stranded cost provision.  
                             (a)  Comments
              Most customer groups and many state representatives (e.g.,
         APPA, Blue Ridge, 253/ National Association of Regulatory
         Utility Commissioners (NARUC) and the Vermont Department of

         251/ Id. at 179-80.
         252/ Id. at 180.
         253/ Blue Ridge consists of Blue Ridge Power Agency, Northeast
              Texas Electric Cooperative, Sam Rayburn G & T Electric
              Cooperative and Tex-La Electric Cooperative.
         Docket Nos. RM95-8-000
           and RM94-7-001              -161-
         Public Service (Vermont Department)) contend that the Cajun
         decision either prevents the Commission from allowing the
         recovery of stranded costs through transmission charges, or, at
         best, raises questions concerning the scope of the Commission's
         legal authority to do so.  In light of Cajun, some commenters,
         such as the National Rural Electric Cooperative Association
         (NRECA), urge the Commission to terminate the NOPR.
              Environmental Action contends that a transmission adder does
         not by itself constitute tying or leveraging.  It submits that if
         the transmission adder consists of costs that a customer is
         obligated to pay in any event, the adder merely holds the
         customer to its existing bargain.  Environmental Action argues
         that in Cajun, however, the transmission adder was not being used
         to recover costs for which the transmission customer was already
         obligated, but had the effect of penalizing the customer for
         entering into a new obligation.  According to Environmental
         Action, the NOPR "makes the same error" to the extent that the
         costs proposed to be recovered in the transmission adder are not
         part of the contractual quid pro quo. 254/  
              All of the investor-owned utility commenters, except
         Wisconsin Power & Light Company (Wisconsin Power), argue that the
         Cajun decision is not a bar to recovery of stranded costs through

         254/ Environmental Action comments at 79.
         Docket Nos. RM95-8-000
           and RM94-7-001              -162-
         transmission rates. 255/  These commenters (e.g., EEI and
         Duke) argue that the Cajun decision was based on procedural
         grounds and merely stands for the proposition that the Commission
         should have held an evidentiary hearing in that case to resolve
         anticompetitive concerns.  These commenters also argue that the
         portion of the Cajun decision relied on by the customer
         commenters is only dictum.  
              Some commenters further contend that allowing the recovery
         of stranded costs through a transmission surcharge does not
         constitute an unlawful tying arrangement.  EEI notes, as an
         initial matter, that the courts no longer view every bundling of
         products or services as a tying arrangement that is per se
         unlawful under the antitrust laws.  Moreover, EEI submits that in
         a tie-in, a seller of one product requires its purchasers to buy
         the tied product by bundling the products together to promote
         sales in related markets that it could not achieve under
         competitive circumstances, effectively foreclosing the purchaser
         from obtaining the second product from competitors even if it
         could do so at a lower cost.  EEI argues that a stranded cost
         surcharge, in contrast, would include only part of the former
         price of the power (the mark-up above its marginal cost included
         in the price approved by regulators), and would thereby allow the
         purchaser to obtain bulk power from competitive suppliers with

         255/ Wisconsin Power argues that stranded costs should be
              recovered, but not through transmission rates.
         Docket Nos. RM95-8-000
           and RM94-7-001              -163-
         the lowest marginal costs.
              With regard to the potential anticompetitive effects of
         allowing stranded cost recovery, some commenters contend that
         stranded cost recovery would inhibit the movement toward
         competition, distort price signals, result in inefficient
         decisionmaking, and unfairly reward the least efficient
         utilities.
              For example, APPA argues that charges for stranded costs are
         anticompetitive and hinder the development of a competitive
         market by, among other things:  (1) distorting transmission
         prices and erecting artificial barriers to new suppliers; (2)
         giving the host utility a paid-off asset with which to compete
         unfairly; and (3) slowing the introduction of new technology.
         APPA argues that the disallowance of stranded costs would
         encourage all utilities to strive for greater efficiencies and to
         compete for sales on the basis of price and service.
              The Ad Hoc Coalition on Environmental and Consumer
         Protection (Ad Hoc Coalition) argues that stranded cost recovery
         will amount to a government-ordered subsidy for electric
         generation from older, less efficient units that will further
         environmental degradation and stifle the move toward greater
         competition.  It claims that the stranded costs that utilities
         primarily will be seeking to recover are uneconomical nuclear
         generation assets, and that the NOPR thus offers a new subsidy
         for nuclear power by shifting cost responsibility for nuclear
         Docket Nos. RM95-8-000
           and RM94-7-001              -164-
         assets from shareholders to ratepayers.  The Ad Hoc Coalition
         believes that such a subsidy could affect investment decisions
         for the next generation of nuclear power plants if investors
         believe that they will be allowed to recover their costs as long
         as a "reasonable expectation" existed at the time the decision to
         build was made.  Thus, the Ad Hoc Coalition argues that the NOPR
         will send an improper signal to utility managers and investors
         that generation investments remain safe investments, even when
         they do not pass the tests of a competitive market.  According to
         the Ad Hoc Coalition, such a policy perpetuates the continued
         reliance on older, less efficient generating units that harm the
         environment.
              American Forest asserts that blanket assurances of stranded
         cost recovery are anticompetitive and create no incentive for
         utilities to lower their operating costs and mitigate any
         uneconomic costs.  According to American Forest, stranded costs
         create enormous uncertainty that may make financing of
         competitors' plants impossible at any cost, thus killing the very
         competitive market the Commission seeks to foster.
              The Illinois Commission believes that stranded cost recovery
         produces an incorrect competitive result because such action
         effectively "props up" the least efficient (high-cost and high-
         price) utilities.  The Illinois Commission argues that stranded
         cost recovery mechanisms effectively punish the more efficient
         suppliers that have paid attention to changing realities and have
         Docket Nos. RM95-8-000
           and RM94-7-001              -165-
         assumed a more competitive market-sensitive posture.
              In sharp contrast to the commenters that argue stranded cost
         recovery would hinder competition, commenters such as EEI, the
         United States Department of Energy (DOE), the Coalition for
         Economic Competition, 256/ and the Conservation Law
         Foundation (CLF) 257/ contend that stranded cost recovery can
         promote a quicker transition to competition and can be used to
         enhance efficiency.  Some commenters (e.g., DOE, Industrial
         Consumers, Enron Power Marketing, Inc. (Enron), CLF, and the
         Competitive Electric Market Working Group (Competitive Working
         Group) 258/) suggest linking the recovery of stranded costs
         to utility actions that will further wholesale competition, such
         as the filing of an open access transmission tariff or membership
         in a regional transmission group (RTG).  
              Commenters representing the financial community (e.g.,
         Utility Investors and Analysts, American Society of Utility
         Investors, United Utility Shareholders Association of America)

         256/ The Coalition for Economic Competition consists of the
              following New York investor-owned utilities:  Central Hudson
              Gas & Electric Corporation, Consolidated Edison Company of
              New York, Long Island Lighting Company, New York State
              Electric & Gas Corporation, Niagara Mohawk Power
              Corporation, and Rochester Gas & Electric Company.
         257/ CLF is a non-profit environmental law organization that
              represents approximately 10,000 members in the six New
              England states.
         258/ The Competitive Working Group consists of Electric
              Clearinghouse, Inc., Enron Power Marketing, Inc., and Destec
              Power Services, Inc.
         Docket Nos. RM95-8-000
           and RM94-7-001              -166-
         strongly support recovery of stranded costs so that the financial
         stability of the electric utility industry will be protected.
         These commenters argue that the amount of potential stranded
         costs exceeds the amount of equity investment in electric
         utilities.  According to these commenters, investors have not
         made their current investment decisions with the rigors of
         competition in mind, nor have rate of return hearings included
         testimony concerning competitive risk.  Without full recovery of
         stranded costs, financial community commenters argue, financial
         integrity will deteriorate, and utilities will be unable to
         attract capital.  Due to the capital-intensive nature of the
         electric utility industry, these commenters note that lack of
         access to capital markets at reasonable rates will prevent
         utilities from keeping costs down.
                             (b)  Preliminary Findings
              We do not interpret the Cajun court decision as barring the
         recovery of stranded costs.  Rather, the Cajun court remanded the
         case because the Commission failed to hold an evidentiary hearing
         concerning whether the inclusion of a stranded cost recovery
         provision in Entergy's transmission tariff precluded the
         mitigation of Entergy's market power.  As previously discussed,
         the court also found the Commission's substantive decision flawed
         because the Commission failed to explain adequately its approval
         of the stranded cost provision, among others.  In this
         consolidated proceeding (i.e., the Stranded Cost NOPR, the
         Docket Nos. RM95-8-000
           and RM94-7-001              -167-
         Supplemental Stranded Cost NOPR, and the Open Access NOPR), we
         are providing the evidentiary record for addressing all of the
         court's concerns on a generic basis, and the opportunity for all
         participants in the electric industry to present evidence and
         arguments.  We are also providing a full explanation of why the
         recovery of legitimate stranded costs is critical to the
         successful transition of the electric utility industry from a
         tightly regulated, cost-of-service industry to an open
         transmission access, competitive industry that will drive down
         the prices of electricity to consumers.    
              The court in Cajun was concerned about whether Entergy's
         tariff allowed "meaningful" access to alternative suppliers.  In
         this regard, the court stated that the Commission must address
         not only whether the stranded cost provision allowed for
         meaningful access, but also whether other provisions in the
         tariff might lessen the utility's market power.  In the Open
         Access NOPR, the Commission is attempting to mitigate the core of
         market power not only for Entergy, but for all traditional public
         utilities:  control over transmission access.  The Commission is
         generically addressing all aspects of transmission market power,
         including those specifically identified by the Cajun court (e.g.,
         point-to-point service limitations).  Indeed, a fundamental
         purpose of the Open Access NOPR is to ensure the meaningful
         access to alternative suppliers that was identified by the Cajun
         Docket Nos. RM95-8-000
           and RM94-7-001              -168-
         court. 259/  The Open Access NOPR includes the specific terms
         and conditions of access (contained in the pro-forma tariffs)
         that we believe are the minimum necessary to mitigate
         transmission market power. 260/  Of utmost importance in
         mitigating market power is the Commission's non-discrimination
         (comparability) requirement, a requirement that had not been
         articulated at the time of the Commission's order under review in
         Cajun, and that is proposed to be codified in the Open Access
         NOPR proceeding.
              With regard to the Cajun court's concern about stranded cost
         provisions, the Commission in Entergy failed to articulate the
         transition that the industry is experiencing, the fundamental
         fact that full competition is not yet a reality, and that
         stranded costs are a temporary but serious phenomenon that must
         be addressed if we are to successfully move from one regulatory
         regime to another, thereby creating fully competitive bulk power
         markets.  In this regard, the Open Access NOPR provides a
         detailed explanation of the fundamental industry and regulatory

         259/ See Cajun, 28 F.3d at 179.
         260/ In seeking comment in the Open Access NOPR on the adequacy
              of these terms and conditions, we seek specific comment on
              the terms and conditions that were of concern to the Cajun
              court.  See discussion supra Section III.E.4.  For example,
              the Cajun court expressed concern that the point-to-point
              service limitation in Entergy's transmission tariff might
              restrain competition.  However, under the Open Access NOPR,
              service will not be limited to point-to-point.  Instead,
              customers will be allowed to choose between point-to-point
              and network service.
         Docket Nos. RM95-8-000
           and RM94-7-001              -169-
         changes that have given rise to the potential for stranded costs.
         In addition, in the Stranded Cost NOPR and the Supplemental
         Stranded Cost NOPR, we have gathered (and are continuing to
         gather) information concerning the magnitude of potential
         stranded costs; we have provided an explanation of the
         transitional nature of stranded costs; and we have explained the
         critical need to deal with these costs in order to reach
         competitive wholesale markets.  We have also explained existing
         disparities in electricity rates and the consumer benefits that
         can accrue if we achieve fully competitive markets. 261/
              Failure to deal with the stranded cost problem would likely
         delay and would certainly complicate the transition to fully
         competitive bulk power markets.  For example, stranded costs
         would then be borne by the utilities' shareholders, which could
         threaten the stability of the industry and the service it
         provides, or be reallocated to remaining customers, raising the
         price to such customers.  An additional consideration is the fact

         261/ There is a wide disparity in consumer electricity prices
              across the United States.  Some consumers pay more than 10
              cents per kilowatt-hour on average, while others pay about
              one-third as much.  While some of this price disparity is
              due to regional cost differentials, some of it may also be
              due to ineffective access to new power supplies.  We believe
              that all consumers will benefit from changes that allow
              their suppliers greater access to lower-cost power supplies.
              This greater access can best be achieved by ensuring that
              non-discriminatory open access transmission service is
              available to all potential users of the transmission grid.
              The result will be greater trading opportunities among
              suppliers, and also more investment opportunities for new
              entrants in generating markets.  All of this should serve
              the interests of consumers by lowering electricity prices.
         Docket Nos. RM95-8-000
           and RM94-7-001              -170-
         that the AGD court instructed the Commission that it must
         consider the transition costs borne by regulated utilities when
         the Commission changes the regulatory rules of the game.
              We conclude that stranded cost recovery as proposed in this
         rulemaking is not a tying arrangement, as discussed by the Cajun
         court, and that the proposed cost recovery procedure will not
         "cabin" market power. 262/  Rather, the stranded cost
         recovery procedure is being prescribed to enable utilities,
         during a transitional period, to recover costs prudently incurred
         under a different regulatory regime.  
              Finally, the financial community argues strongly and
         plausibly that recovery of legitimate and verifiable stranded
         costs at this critical stage in the industry's move toward
         competition is  needed to protect the financial stability of the
         electric industry.  They confirm that the prospect of not
         recovering stranded costs could erode a utility's ability to
         attract capital, which, in turn, could impede the long-term goal
         of achieving competitive wholesale markets.
                        (3)  Responsibility for Wholesale Stranded Costs
                             (Whether to Adopt Direct Assignment to
                             Departing Customers)
              In the initial NOPR, the Commission proposed to allow
         utilities to seek to assign stranded costs associated with the
         departure of a given wholesale customer directly to that

         262/ Cajun, 28 F.3d at 177-78.
         Docket Nos. RM95-8-000
           and RM94-7-001              -171-
         departing wholesale customer. 263/  We noted, however, that
         an alternative might be to assign stranded costs more broadly by,
         for example, requiring all transmission customers (including
         native load which takes bundled service) to pay a higher rate for
         use of the transmission system.  We invited comments on the
         direct assignment and alternative methods of stranded cost
         recovery. 264/
                             (a)  Comments
              Many parties (representing all constituencies) support the
         direct assignment of stranded costs to the departing customer as
         proposed in the initial NOPR.  Most commenters contend that the
         cost causation principle supports this approach.  These parties
         argue that utilities undertake obligations on a customer's behalf
         and that, by leaving the system, the departing customer avoids
         paying for its fair share of these obligations.  They further
         argue that general fairness requires that customers remaining on
         the system should not have to pay for a departing customer's
         obligations; they allege that this could lead to more customers
         leaving the system and the eventual bankruptcy of the utility.  
              Nevertheless, other commenters suggest a framework for
         stranded cost recovery that is different from the direct

         263/ Methods of direct assignment include a lump sum payable when
              the customer leaves the system.  Such an exit fee could also
              be recovered over time in monthly installments.  Presumably
              the utility would charge interest on the unamortized balance
              if the customer selected a delayed payment approach.
         264/ Stranded Cost NOPR at 32,867-68.
         Docket Nos. RM95-8-000
           and RM94-7-001              -172-
         assignment method suggested in the NOPR.  According to some
         commenters (e.g., South Carolina Electric & Gas Company),
         stranded costs should be allocated to all customers and
         shareholders because everyone will benefit from the transition to
         competitive generation markets.  In this manner, they contend
         that the overall burden would be reduced, because stranded costs
         would be spread among a greater number of parties.  Commenters
         that support spreading the costs to all customers argue that
         requiring the departing customer to shoulder all stranded costs
         will result in few customers going off-system due to the economic
         inefficiency of paying two suppliers.  Several commenters (e.g.,
         Indiana Commission, Rhode Island Division of Public Utilities and
         Carriers, Department of Water and Power of the City of Los
         Angeles, and Fuel Managers Association) suggest that some
         shareholder liability for stranded cost recovery should be
         required, arguing that it would provide utilities with a greater
         incentive to mitigate stranded costs.
              Some commenters support the recovery of stranded costs
         through a transmission surcharge applicable to all transmission
         customers. 265/     

         265/ Some commenters (e.g., Allegheny Power) distinguish between
              transmission surcharges imposed on transmission-only
              customers as opposed to all customers.  In the former case,
              only those customers taking transmission-only service from
              the utility would be assessed stranded costs; customers
              taking bundled service would not be assessed such costs.
              Allegheny Power indicates that it would support such an
              approach only if the Commission decides not to fully assign
              stranded costs to departing customers.
         Docket Nos. RM95-8-000
           and RM94-7-001              -173-
              Other commenters oppose a general surcharge on all
         transmission customers, arguing that existing transmission
         customers, including native load, should not be allocated any
         stranded costs because they did not cause any costs to be
         stranded in the first place.  Washington Water Power Company and
         Wisconsin Electric Power Company oppose a transmission surcharge
         on the basis that it makes an otherwise competitive supplier less
         marketable due to higher wheeling rates.  Others allege that a
         transmission surcharge is inconsistent with the unbundling of
         transmission service and would slow the restructuring
         (disaggregation) of vertically-integrated utilities.  Thus,
         according to some commenters, the use of a transmission surcharge
         would slow the move to competitive markets because the surcharge
         sends the wrong price signal, involves cross-subsidization by
         native load, penalizes competitive alternatives, and awards
         monopoly rents to the utility.  Some commenters also note that,
         where the departing customer does not take transmission service
         from its former supplier, the departing customer escapes all
         responsibility for the stranded costs.   
              Some commenters contend that the Cajun decision prohibits
         the use of a transmission surcharge.  Still others argue that
         generation costs should not be assigned to transmission users
         because utilities would then have an incentive to shift costs to
         transmission in order to make their generation more competitive.
         SCOOP argues that the shifting of generation costs to
         Docket Nos. RM95-8-000
           and RM94-7-001              -174-
         transmission rates violates the Commission's policy prohibiting
         costs unrelated to the transmission function from being included
         in transmission charges. 266/
              The Public Utility Commission of Texas (Texas Commission)
         proposes a hybrid approach whereby a portion of stranded costs
         would be directly assigned to the departing customer and the
         remainder allocated through a general surcharge to all wholesale
         market participants.  However, if a general surcharge on
         transmission customers is adopted, the Texas Commission supports
         the pooling of all stranded costs and the creation of an
         industry-wide surcharge.  The Texas Commission does not explain
         how such a pool would be administered. 267/
              Commenters that represent shareholder interests (American
         Society of Utility Investors, United Utility Shareholders
         Association of America, and Utility Investors and Analysts) argue
         against allocation of any stranded costs to shareholders because
         the rates of return granted to utilities in the past have not
         included any compensation for the risk of competition.  They
         submit that fairness dictates that those placed at risk by a
         sudden change in the rules not be penalized.  Tennessee Valley
         Authority (TVA), which as a Federal corporation has no

         266/ SCOOP comments at 38 (citing Northern States Power Company,
              Opinion No. 383, 64 FERC ¶ 61,324 at 63,377 (1993)).
         267/ Trigen Energy Corporation advocates that Congress impose a
              "sunset" energy tax on all electricity used in order to pay
              off stranded costs.  
         Docket Nos. RM95-8-000
           and RM94-7-001              -175-
         shareholders to absorb stranded costs, shares this view.
                             (b)  Preliminary Findings
              After careful consideration of the various comments, we
         believe that direct assignment of stranded costs to the departing
         wholesale customer, as proposed in the initial NOPR, is the
         appropriate method for recovery of such costs. 268/  This
         method is consistent with the cost causation principle. 269/
         As discussed in greater detail below, as part of the evidentiary

         268/ Because we are also proposing to entertain requests for
              recovery of stranded costs attributable to retail-turned-
              wholesale wheeling customers, or to retail wheeling
              customers in certain limited circumstances, our
              determinations and rationale regarding direct assignment
              also apply to those situations.
         269/ Contrary to arguments made by SCOOP, the shifting of
              generation costs to transmission rates does not violate
              Commission policy.  The Northern States case cited by SCOOP
              deals with the Commission's bright line functionalization
              policy, pursuant to which the Commission, largely as a
              matter of administrative convenience, has attempted to
              maintain a boundary between generation and transmission
              functions.  In that case, we found that refunctionalization
              is not per se improper or contrary to Commission policy, and
              we suggested that strict application of the traditional
              bright line approach may need to be reexamined in light of
              changes taking place in the electric industry.  64 FERC at
              63,379.  Significantly, we stated that the "fundamental
              theory of Commission ratemaking is that costs should be
              recovered in the rates of those customers who utilize the
              facilities and thus cause the costs to be incurred."  Id.
              (emphasis in original).
                   This is exactly what we propose to do in the Stranded
              Cost NOPR and the Supplemental Stranded Cost NOPR.  The
              customer that caused the costs to be incurred and stranded
              will continue to pay the costs.  The only difference is that
              in some instances the customer will pay the costs through an
              adder to its transmission rate instead of through a
              generation rate.
         Docket Nos. RM95-8-000
           and RM94-7-001              -176-
         demonstration necessary for stranded cost recovery associated
         with certain departing wholesale requirements customers, 270/
         retail-turned-wholesale transmission customers, or unbundled
         retail transmission customers, a utility must show that the costs
         are not more than the customer would have contributed to the
         utility had the customer continued to take generation service
         from that utility.  We believe it only appropriate that the
         departing customer, and not the remaining customers (or
         shareholders), bear its fair share of the legitimate and prudent
         obligations that the utility undertook on that customer's behalf.
              The Commission recognizes that the direct assignment
         approach for addressing stranded costs for the electric industry
         differs from the approach eventually taken for the natural gas
         industry.  In Order No. 636, which involved the restructuring of
         the gas industry, the Commission determined that it was
         appropriate to spread the majority of the remaining transition
         costs associated with take-or-pay and other contracts to all
         customers (existing and new) using the interstate natural gas
         transportation system. 271/  However, unlike the situation
         facing the electric utility industry today, by the time the
         Commission issued Order No. 636, changes in the natural gas

         270/ I.e., departing wholesale requirements customers under
              contracts entered into on or before July 11, 1994, who will
              use the utility's transmission system to reach other
              suppliers and whose contracts do not explicitly address
              stranded costs.
         271/ Order No. 636 at 30,457-62.
         Docket Nos. RM95-8-000
           and RM94-7-001              -177-
         industry had progressed to such a point that it was not possible
         for the Commission to use a strict cost causation approach.  Many
         natural gas customers had already left their historical pipeline
         suppliers' systems.  Others had converted from sales and
         transportation customers to transportation-only customers.
         Others were in a transition stage having had opportunities to
         lower their contract demands or otherwise become partial service
         customers.  Significant take-or-pay and other costs had
         accumulated.  In contrast, in the electric area, the Commission
         (and the states) will be better able to address the transition
         cost issue up front, and to address stranded cost recovery before
         customers leave their suppliers' systems.  This, in effect, will
         prevent the accumulation of unrecovered costs and will comport
         with our past policy of assigning costs to customers who caused
         the costs to be incurred.
              In addition, allowing direct assignment of stranded costs
         will ensure that there are no stranded costs left to be borne by
         the remaining customer base or by the shareholders.  This, in
         turn, will ensure that the financial health of the industry is
         not placed in jeopardy.  If some customers are permitted to leave
         their suppliers without paying for costs incurred to serve them,
         this may cause an excessive burden on the remaining customers
         (such as residentials) who cannot leave and therefore may have to
         bear those costs.  Moreover, the prospect or lack thereof for
         recovering such costs from ratepayers could erode a utility's
         Docket Nos. RM95-8-000
           and RM94-7-001              -178-
         access to capital markets or significantly increase the utility's
         cost of capital.  This higher cost of capital could precipitate
         other customers leaving the system which, in turn, could cause
         others to leave.  Such a spiral could be difficult to stop once
         begun.
              The alternatives to direct assignment of stranded costs are
         to do nothing or to assess stranded costs more broadly through
         some type of general surcharge on all customers.  As discussed
         above, to do nothing would mean that the Commission would have to
         reallocate stranded costs to shareholders or to remaining
         customers.  Those customers that caused the costs to be stranded
         would not have to pay.  This would violate the cost causation
         principle which has been fundamental to the Commission's
         regulation since 1935.  The other alternative, to assess costs
         more broadly, also violates this principle.  Moreover, there
         appears to be no strong countervailing reason to assess costs
         broadly in the electric utility industry.  
                        (4)    Recovery of Stranded Costs Associated With
                               New Wholesale Power Sales Contracts
              The NOPR proposed that public utilities and transmitting
         utilities would not be permitted to seek extra-contractual
         recovery of stranded costs associated with "new" contracts, i.e.,
         contracts executed after July 11, 1994, through transmission
         rates for section 205 or 211 transmission services.  For new
         contracts, the NOPR proposed that stranded cost recovery would be
         allowed only if explicit stranded cost provisions are contained
         Docket Nos. RM95-8-000
           and RM94-7-001              -179-
         in the contract accepted by the Commission. 272/  We also
         stated our preliminary view that it is not appropriate in this
         new regime to impose on wholesale requirements suppliers any
         regulatory obligation to continue to serve their existing
         requirements customers beyond the end of the contract term.
         However, we invited comment on the extent to which there should
         be such an obligation.  We also sought comment concerning whether
         section 35.15 of the Commission's regulations, concerning notice
         of termination, should be deleted.
                             (a)  Comments
              Some of the commenters dispute the Commission's belief that
         there should not be a future regulatory obligation to continue to
         serve wholesale requirements customers beyond the end of the
         contract.  SCOOP argues that the FPA imposes an obligation on a
         public utility to continue wholesale service beyond the term of
         the contract when such service is required by the public
         interest, and that the Commission does not have the power to
         abrogate this authority.  Sunflower Electric Power Corporation
         (Sunflower) submits that, for stability reasons, a utility's
         obligation to serve requirements customers should run beyond the

         272/ Under the proposed regulations, a public utility may seek
              recovery of such costs in accordance with the contract.
              However, if wholesale stranded costs are associated with a
              new wholesale requirements contract and the seller under the
              contract is a transmitting utility but not also a public
              utility, the transmitting utility may not seek an order from
              the Commission allowing recovery of such costs.  See
              Stranded Cost NOPR at 32,882.
         Docket Nos. RM95-8-000
           and RM94-7-001              -180-
         end of the contract term.
              Some commenters (e.g., SCOOP, Sunflower, Illinois
         Commission) generally support Commission retention of its section
         35.15 notice of termination filing requirement, arguing that such
         filing requirement is reasonable and/or necessary to ensure that
         any termination in service is not contrary to the public
         interest.     
              Other commenters support the Commission's position that
         there should not be a future regulatory obligation to continue to
         serve wholesale requirements customers beyond the end of the
         contract and support modification or elimination of section
         35.15.  These commenters argue that if contracts are to govern
         future requirements relationships in the electric industry, the
         Commission should allow the contracts to terminate on their own
         terms, without the need for a filing and Commission approval.
         New England Power Company submits that continuation of such a
         filing requirement would add uncertainty to the parties' mutually
         agreed upon termination date and, in turn, promote inequitable
         and asymmetrical risk/benefit allocations and ineffective
         resource planning.  EEI asks the Commission to make a finding
         that it is in the public interest to end the regulation of the
         termination of bulk power contracts.  EEI suggests that the
         Commission could (1) grant a blanket waiver of the regulations
         requiring notice of termination for new contracts; (2) amend
         section 35.15 to pre-grant waiver of notice of termination; or
         Docket Nos. RM95-8-000
           and RM94-7-001              -181-
         (3) amend the regulations to pre-grant waiver of notice of
         termination in all bulk power contracts signed after the
         Commission makes its public interest finding to end the
         regulation of contract terminations.
                             (b)  Preliminary Findings
              The Commission believes that future wholesale contracts
         should explicitly address the mutual obligations of the seller
         and buyer, including the seller's obligation to continue to serve
         the buyer, if any, and the buyer's obligation, if any, if it
         changes suppliers.  Now that utilities have been placed on
         explicit notice that the risk of losing customers through
         increased wholesale competition must be addressed through
         contractual means only, they must address stranded cost issues
         when negotiating new contracts or be held strictly accountable
         for the failure to do so.  Accordingly, public utilities and
         transmitting utilities will be allowed stranded cost recovery
         associated with new contracts (executed after July 11, 1994) only
         if explicit stranded cost provisions are contained in the
         contract.  Recovery of wholesale stranded costs associated with
         any new requirements contract (executed after July 11, 1994) will
         not be allowed unless such recovery is provided for in the
         contract.
              Further, to ensure that the rights and obligations of
         sellers and buyers are symmetrical in the new competitive era, we
         Docket Nos. RM95-8-000
           and RM94-7-001              -182-
         do not believe that it is appropriate to impose on wholesale
         requirements suppliers a regulatory obligation to continue to
         serve their existing requirements customers beyond the end of the
         contract term.  A requirements customer thus will be responsible
         for planning to meet its power needs beyond the end of the
         contract term.  In this regard, it may sign a new contract with
         its existing supplier, or it may contract with new suppliers in
         conjunction with obtaining transmission service under its
         existing supplier's open access transmission tariff.  
              We believe that the section 35.15 filing requirement should
         be retained for all contracts required to be filed under sections
         205 and 206 of the FPA that were executed prior to the effective
         date of the generic tariffs that we discuss herein. 273/
         With regard to any power sale contract executed on or after that
         date, 274/ we propose to no longer require prior notice of
         termination pursuant to the provisions of section 35.15.
         However, for administrative reasons, we will require written
         notification of the termination of such contract within 30 days
         after the date termination takes place.

         273/ We also propose to retain the section 35.15 filing
              requirement for any unexecuted contracts that were filed
              prior to the effective date of the generic tariffs proposed
              herein.
         274/ We request comments on whether this proposal should also be
              applied to transmission contracts.
         Docket Nos. RM95-8-000
           and RM94-7-001              -183-
                   (5)  Recovery of Stranded Costs Associated With
                        Existing Wholesale Power Sales Contracts
              In the initial Stranded Cost NOPR (and again in this
         Supplemental NOPR) we stated that stranded costs are a
         transitional problem and that neglecting their recovery could
         delay the realization of fully competitive bulk power markets.
         We stated that it is thus important to set a date beyond which
         the Commission will no longer permit extra-contractual recovery
         of stranded costs that result from existing requirements
         contracts.  To that end, we proposed a three-year transition
         period during which public utilities must attempt and non-public
         utilities are encouraged to attempt to renegotiate certain
         existing wholesale requirements contracts (i.e., those that do
         not explicitly address stranded costs through an exit fee or
         other stranded cost provision), and during which they may seek
         recovery of stranded costs.  However, if an existing wholesale
         requirements contract explicitly addresses stranded costs through
         an exit fee or other stranded cost provision, the initial NOPR
         would require the utility to recover such costs only as specified
         in the contract; it would not permit unilateral filings to change
         stranded cost provisions and would not permit the utility to seek
         recovery through transmission rates of stranded costs associated
         with that contract.  Under the initial NOPR, existing contracts
         that prohibit stranded cost recovery, or explicitly prohibit
         renegotiation of an existing stranded cost or exit fee provision,
         or that prohibit renegotiation until after the three-year period
         Docket Nos. RM95-8-000
           and RM94-7-001              -184-
         has expired would not be subject to the obligation to
         renegotiate. 275/
              Where an existing contract does not contain a stranded cost
         provision and the parties to the contract are unable to negotiate
         a stranded cost amendment, and the selling utility is a public
         utility, the initial NOPR proposed to permit the public utility
         to unilaterally file under section 205 or 206 of the FPA prior to
         the end of the three-year period a proposed stranded cost
         provision as an amendment to the existing contract.  The NOPR
         also proposed to permit the selling public or transmitting
         utility to seek to recover stranded costs through jurisdictional
         transmission rates if, prior to the end of the three-year
         transition period, the customer under the existing wholesale
         requirements contract gives notice pursuant to the contract that
         it will no longer purchase all or part of its requirements from
         the selling utility, but instead will purchase unbundled section
         205 or section 211 transmission services from the selling utility
         that will begin prior to the end of the three-year period.  
              Under the initial NOPR, if a contract does not include an
         exit fee or other explicit stranded cost provision, but does
         contain a notice provision, the Commission proposed that there be
         a rebuttable presumption that the selling utility had no
         reasonable expectation of continuing to serve the customer beyond

         275/ The parties, of course, could always voluntarily renegotiate
              the contract.
         Docket Nos. RM95-8-000
           and RM94-7-001              -185-
         the period provided in the notice provision.  We proposed to
         apply such presumption when the public utility proposed a
         unilateral amendment to the contract to change the notice
         provision and/or add an exit fee provision, or if the public
         utility or transmitting utility sought stranded cost recovery
         through transmission rates. 276/
              The Commission recognized that some utilities' existing
         contracts may not provide for unilateral rate changes.  We noted
         that although under the Mobile-Sierra doctrine 277/ a
         customer may waive its right to challenge the contract and/or the
         utility may waive its right to make unilateral rate changes, the
         parties may not waive the indefeasible right of the Commission to
         alter rates that are contrary to the public interest.  We went on
         to explain why we believe that it is in the public interest to
         permit public utilities with Mobile-Sierra contracts a limited
         opportunity to propose contract changes unilaterally to address
         stranded costs if their contracts do not already explicitly do
         so.
              In the NOPR, the Commission invited comments regarding,
         among other things, whether there should be a transition period
         during which utilities may renegotiate existing contracts, the
         appropriate length for such a transition period, whether

         276/ Stranded Cost NOPR at 32,861; 32,869-70.
         277/ See United Gas Pipeline Company v. Mobile Gas Service
              Corporation, 350 U.S. 332 (1956); FPC v. Sierra Pacific
              Power Company, 350 U.S. 348 (1956).
         Docket Nos. RM95-8-000
           and RM94-7-001              -186-
         utilities or customers with contracts that do not provide for
         unilateral amendments should be able to make unilateral filings
         or file complaints, whether the Commission should make a Mobile-
         Sierra public interest finding based on company-specific findings
         instead of generic industry-wide findings, the types of
         contractual provisions that might demonstrate a sufficient
         meeting of the minds between the parties so that requiring
         renegotiation would be inappropriate, whether to apply the rules
         regarding existing contracts only to contracts between
         unaffiliated entities, and whether the rebuttable presumption
         should also be applied to any contract entered into after the
         date of enactment of the Energy Policy Act, even though the
         contract does not contain an exit fee or other explicit stranded
         cost provision or a notice provision.
                                  (a)  Comments
                             (i)  Contract Renegotiation
              Investor-owned utilities, EEI, and the majority of state
         commissions generally favor renegotiation of requirements
         contracts. 278/  These commenters argue that the transition
         to a competitive market should not preclude utilities from
         recovering costs prudently incurred to serve customers who may

         278/ Notable exceptions to this general observation include
              Southern California Edison Company, which opposes
              renegotiation of Mobile-Sierra contracts, and the
              Pennsylvania Public Utility Commission (Pennsylvania
              Commission) and the Vermont Department, which favor
              upholding the sanctity of contracts.
         Docket Nos. RM95-8-000
           and RM94-7-001              -187-
         wish to leave the system that was planned and built to serve the
         customers' needs.
              Commenters representing cooperatives, municipal, industrial
         customers, and independent power producers generally oppose
         renegotiation.  These commenters suggest that the framework
         established in the NOPR, requiring good faith renegotiation of
         contracts and permitting the unilateral filing of revised
         contracts to provide for recovery of stranded costs (where
         renegotiation fails), will result in a violation of the Mobile-
         Sierra doctrine.  Numerous commenters argue that contracts should
         stand on their own, and that there is no factual record upon
         which the Commission can make a generic public interest finding,
         as required by Mobile-Sierra, that contracts should be modified.
         These commenters maintain that "assumed" threats to the financial
         stability of the industry do not meet the extremely heavy Mobile-
         Sierra burden of proof that is required to release a public
         utility from a contract.  They argue that it is not the
         Commission's place to relieve utilities of improvident bargains.
         Many customer group commenters argue that requiring contract
         renegotiation improperly shifts the burden of proof from the
         utility to the customer.  These commenters further argue that
         permitting contract renegotiation implies that customers should
         pay for a utility's failure to protect itself from business risk.
              Some commenters, such as American Forest, argue that the
         NOPR would, in essence, rewrite the law of contracts.  These
         Docket Nos. RM95-8-000
           and RM94-7-001              -188-
         commenters state that there is no legal (or logical) basis for
         the NOPR's suggestion that wholesale customers with existing
         contracts containing valid notice of termination provisions can
         be forced to renegotiate such contracts to allow stranded cost
         recovery.  Many of these commenters cite Boston Edison Company
         279/ and Arizona Public Service Company 280/ for the
         proposition that notice provisions have been allowed and
         enforced.  Many commenters contend that contract renegotiation is
         unfair because the policy would make the terms of existing
         contracts binding on only one party, while letting the other
         party unilaterally revise contract terms.
              Some commenters, including the Electric Generation
         Association and the Iowa Utilities Board, generally oppose
         renegotiation, but would allow it in certain situations.  They
         state that a utility's right to recover stranded costs should
         depend on the terms for which the parties have bargained.
         However, they recognize that there may be situations in which the
         parties' intent is not clearly defined.  Accordingly, these
         commenters support renegotiation to supply missing terms to an
         ambiguous contract.  Some commenters such as the Iowa Utilities
         Board maintain that companies should always be free to
         renegotiate contracts; however, they oppose allowing utilities to
         make unilateral filings to amend contracts that do not provide

         279/ 56 FPC 3414 (1976).
         280/ 18 FERC ¶ 61,197 (1982).
         Docket Nos. RM95-8-000
           and RM94-7-001              -189-
         for unilateral amendment.
              With regard to whether the renegotiation proposal should
         apply only to contracts between unaffiliated entities, some
         commenters (e.g., Wisconsin Power, Sunflower) support the
         application of the renegotiation policy to both affiliated and
         non-affiliated entities alike.  However, other commenters (e.g.,
         the Ohio Office of the Consumers' Counsel) recommend that the
         Commission not apply the proposed renegotiation rule to
         affiliated entities.  They note that due to the mutual interest
         of affiliates, negotiations between them may not be arm's-length.
         These commenters urge the Commission to review all stranded
         investment agreements between affiliates to prevent cross-
         subsidization and to prevent interference with competition.
                             (ii)  Three-Year Transition Period
              With regard to the proposed transition period, although some
         commenters argue against permitting contract renegotiation,
         commenters generally raise no serious objections to three years
         as the period for contract negotiation.  However, several
         commenters suggest that it is undesirable and unnecessary to
         delay the movement to competition for three years while contract
         renegotiations take place.  For example, the Competitive Working
         Group argues that there is no assurance that stranded cost
         recovery will be resolved during the three-year period proposed
         in the initial notice.  It suggests that the Commission could
         shorten the transition to competition while still providing for
         Docket Nos. RM95-8-000
           and RM94-7-001              -190-
         recovery of stranded costs by requiring that eligibility for
         recovery be conditioned on utilities agreeing to:  (1) grant
         wholesale customers the right to reduce or terminate purchase
         obligations under preexisting contracts and to convert to
         transmission-only service; (2) file comparable open-access
         transmission tariffs; and (3) mitigate the level of stranded
         assets by either divestiture or auction.  The Competitive Working
         Group claims that these measures would ensure the move to
         competitive wholesale power markets.
              DOE, Industrial Consumers, Enron and CLF also suggest
         linking the recovery of stranded costs to utility actions that
         will further wholesale competition.  These commenters suggest
         linking the recovery of stranded costs to the filing of an open
         access transmission tariff or membership in an RTG.  CLF notes
         that environmental as well as economic benefits may be achieved
         by linking the recovery of stranded costs to the retirement of
         environmentally unsuitable electric generating plants or
         initiatives that encourage the development and deployment of
         renewable and clean energy technologies.
              Detroit Edison Company (Detroit Edison) suggests that the
         renegotiation period be the greater of (1) three years, (2) the
         term of any existing contract, or (3) the period of any
         moratorium on changes in rates established in existing settlement
         agreements.  According to Detroit Edison, adoption of this
         provision would allow utilities that already have established
         Docket Nos. RM95-8-000
           and RM94-7-001              -191-
         long-term contracts or that have agreed to a moratorium on rate
         changes to honor previously negotiated agreements.
                             (b)  Preliminary Findings
              We reaffirm our proposal to permit the recovery of
         legitimate and verifiable stranded costs for a limited set of
         existing wholesale contracts, namely, contracts executed on or
         before July 11, 1994 that do not already contain exit fees or
         other explicit stranded cost provisions.  We further reaffirm our
         desire that utilities and their customers attempt to renegotiate
         such contracts promptly to specify the rights and obligations of
         the parties.  To that end, we encourage the parties to existing
         contracts that do not address stranded costs to reach a mutually
         agreeable resolution.  If the parties negotiate such a provision
         and the seller is a public utility, the utility must file the
         provision with the Commission as an amendment to the existing
         requirements contract.  Of course, in some cases, the parties may
         disagree in good faith about whether the utility's expectations
         that the customer would continue taking service were reasonable.
         If so, negotiations may prove unsuccessful.
              In place of the three-year transition period proposed in the
         initial NOPR, we propose that, if an existing requirements
         contract does not contain an exit fee or other explicit stranded
         cost provision and is not mutually renegotiated to add such a
         provision:  (1) a public utility or its customer may, at any time
         prior to the expiration of the contract, file a proposed stranded
         Docket Nos. RM95-8-000
           and RM94-7-001              -192-
         cost amendment to the contract under section 205 or 206; or (2) a
         public utility or transmitting utility may, at any time prior to
         the expiration of the contract, file a proposal to recover,
         through its transmission rates for a customer that uses the
         utility's transmission system to reach another generation
         supplier, stranded costs associated with any such existing
         contract.  However, for a utility to be eligible for recovery of
         stranded costs, it must meet the evidentiary and procedural
         criteria discussed infra.  
              Consistent with the initial NOPR, if an existing contract
         includes an explicit provision for payment of stranded costs or
         an exit fee, we will assume that the parties intended the
         contract to cover the contingency of the buyer leaving the
         system.  As proposed in the initial Stranded Cost NOPR and
         reaffirmed here, we will reject a stranded cost amendment to an
         existing contract that already contains an exit fee or stranded
         cost provision, unless the contract permits renegotiation of the
         existing stranded cost provision or the parties to the contract
         mutually agree to renegotiate the contract.
              However, if a contract does not contain an exit fee or other
         explicit stranded cost provision, and the contract permits the
         seller and/or buyer to seek an amendment to the contract, the
         authorized party may seek an amendment to add a stranded cost
         provision.  In addition, even if the contract contains an
         explicit Mobile-Sierra provision, the Commission reaffirms its
         Docket Nos. RM95-8-000
           and RM94-7-001              -193-
         preliminary determination that it is in the public interest to
         permit public utilities to seek unilateral amendments to add
         stranded cost provisions if the contracts do not already contain
         exit fees or other explicit stranded cost provisions.  If a
         utility demonstrates that it has met the standards for recovery
         outlined in this Supplemental NOPR, we believe that its recovery
         of stranded costs will be in the public interest.
              If neither of the parties to such a contract seeks and
         obtains acceptance or approval of an explicit stranded cost
         amendment, the Commission proposes to permit the public utility
         to seek recovery of stranded costs through its wholesale
         transmission rates.  We also propose to establish procedures to
         provide an existing wholesale requirements customer who is
         contemplating switching suppliers, and using its existing
         supplier's transmission system in order to reach a new supplier,
         advance notice of how the utility would propose to calculate
         costs that the utility claims would be stranded by the customer's
         departure.  We believe that the following procedures would enable
         such a customer to make an informed decision whether or not to
         switch suppliers:
              (1)  A customer may, at any time prior to the termination
                   date specified in its existing wholesale requirements
                   contract, request the public utility to either:  (i)
                   calculate the customer's maximum possible stranded cost
                   exposure without mitigation, as of the date set forth
         Docket Nos. RM95-8-000
           and RM94-7-001              -194-
                   in the customer's request; or (ii) provide the formula
                   that the utility would use to calculate the customer's
                   maximum possible stranded cost exposure without
                   mitigation, to enable the customer to assess whether to
                   contract for new generation service from another
                   supplier.  The customer should specify in its request,
                   to the extent possible, pursuant to its rights under
                   the power sales agreement with the seller, the date on
                   which the customer would substitute alternative
                   generation for the requirements purchase and the amount
                   of the substitution.  Any remaining requirements
                   purchased from the existing supplier after this date
                   should be clearly indicated.  The customer may seek
                   further information on how the stranded cost charge
                   would vary as a result of choosing different dates or
                   different amounts of substitute purchases.  The
                   customer also should indicate its preferred payment
                   method(s) (e.g., a monthly or annual adder to its
                   transmission rate or an up-front lump-sum payment).
              (2)  The utility shall, within thirty days of receipt of the
                   request, or other mutually agreed upon period, provide
                   the customer:  (i) the customer's maximum possible
                   stranded cost exposure without mitigation; or (ii) the
                   formula that the utility would use to calculate the
                   customer's maximum possible stranded cost exposure
         Docket Nos. RM95-8-000
           and RM94-7-001              -195-
                   without mitigation.  The utility's response should
                   indicate the period over which the utility proposes to
                   charge the departing customer.  There should be
                   appropriate support for each element in the calculation
                   or formula to enable the customer to understand the
                   basis for the element.  The utility should provide a
                   detailed rationale for its proposal as to how long the
                   utility reasonably expected to keep the customer.  The
                   utility also should address how it intends to mitigate
                   stranded costs.
              (3)  If the customer believes that the utility has failed to
                   establish that it had a reasonable expectation of
                   continuing to serve the customer beyond the contract
                   term or that the proposed maximum stranded cost charge
                   without mitigation (or formula) is unreasonable, it
                   will have thirty days in which to respond to the
                   utility explaining why it disagrees with the charge.
                   The parties should then attempt to reach a mutually-
                   agreeable charge for stranded costs within a reasonable
                   period.  
              (4)  If the parties are unable to resolve the matter
                   pursuant to the procedures specified in (1)-(3) above,
                   the customer may either:  (a) file a complaint with the
                   Commission under section 206 of the FPA to seek a
                   Commission determination whether the utility has met
         Docket Nos. RM95-8-000
           and RM94-7-001              -196-
                   the reasonable expectation standard and, if so, whether
                   the proposed maximum stranded cost charge (or formula)
                   satisfies the other evidentiary standards set forth in
                   this rule; 281/ or (b) wait until the proposed
                   stranded cost charge is filed under section 205 of the
                   FPA, and contest it at that time. 282/  In either
                   case, i.e., a section 205 or 206 proceeding, the
                   utility would only be able to seek stranded cost
                   recovery according to the formula and other terms
                   identified in its earlier discussions with the
                   customer.
              The above-described procedure would provide a customer an
         opportunity to know its maximum possible exposure as far in
         advance of its decision to change suppliers as the customer
         chooses (i.e., the customer can file its request for a stranded
         cost computation at any time).  If the customer decides to
         contest the proposed stranded cost charge, in either a section
         206 or 205 proceeding, it will know its exact exposure once the
         Commission has completed its review of the proposed charge.  This
         procedure attempts to address the Cajun court's concern that

         281/ If a complaint is filed, neither the customer nor the
              utility could raise issues not identified in their earlier
              discussions.  The burden of proof would be on the utility to
              satisfy the evidentiary standards related to stranded cost
              recovery.
         282/ As discussed in section III.F.1.c(10) infra, retail
              customers contemplating becoming wholesale customers may use
              the same procedures.
         Docket Nos. RM95-8-000
           and RM94-7-001              -197-
         exposure to an unknown stranded cost fee will discourage
         customers from looking at other suppliers.  At the same time,
         this procedure will permit recovery of legitimate stranded costs
         as set forth herein.
              We strongly encourage utilities and their existing customers
         to attempt to resolve stranded cost issues through a mutually-
         agreeable exit fee or other stranded cost amendment to existing
         contracts that do not address stranded cost recovery.
              We invite comments on our proposal to drop the three-year
         negotiation requirement originally proposed in the Stranded Cost
         NOPR, and instead to permit amendments to certain existing
         requirements contracts at any time prior to the expiration of the
         contracts, or to permit utilities to seek recovery through a
         departing customer's transmission rates at any time prior to the
         expiration of the power sales contracts.  We also invite comments
         on our proposal to establish a procedure whereby a wholesale
         requirements customer with an existing contract that does not
         explicitly address stranded costs can obtain its maximum stranded
         cost exposure without mitigation from the utility and can seek
         Commission review of the utility's reasonable expectation claim
         and the utility's proposed stranded cost charge or formula.  
                        (6)  Filing Requirements for Wholesale Stranded
                             Cost Recovery
              The Commission proposes to amend Part 35, Chapter I, Title
         18 of the Code of Federal Regulations to establish filing
         requirements for public utilities (as defined in FPA section
         Docket Nos. RM95-8-000
           and RM94-7-001              -198-
         201(e)) and transmitting utilities (as defined in FPA section
         3(23)) that seek stranded cost recovery.  We reaffirm our view
         that the only circumstance in which transmitting utilities that
         are not also public utilities may seek stranded cost recovery
         from this Commission is through customer-specific surcharges to
         rates for transmission services under FPA sections 211 and 212,
         and that those surcharges may only apply to costs associated with
         existing contracts.
              The proposed regulations define "wholesale stranded cost" as
         "any legitimate, prudent and verifiable cost incurred by a public
         utility or a transmitting utility to provide service to:  (i) a
         wholesale requirements customer that subsequently becomes, in
         whole or in part, an unbundled wholesale transmission services
         customer of such public utility or transmitting utility, or (ii)
         a retail customer, or a newly created wholesale power sales
         customer, that subsequently becomes, in whole or in part, an
         unbundled wholesale transmission services customer of such public
         utility or transmitting utility."
              We seek comment on whether the proposed definition of
         "wholesale stranded cost" should encompass the situation where a
         wholesale requirements customer ceases to purchase power from the
         utility that had been making wholesale requirements sales to such
         customer, and the customer does not thereafter become an
         unbundled transmission services customer of that utility.  This
         situation might occur, for example, in a situation where the
         Docket Nos. RM95-8-000
           and RM94-7-001              -199-
         former requirements customer was in a non-contiguous service area
         and does not need unbundled transmission service from the former
         seller in order to purchase power from a replacement supplier.
              Consistent with the initial Stranded Cost NOPR, the proposed
         regulations would permit a public utility or transmitting utility
         to seek recovery of wholesale stranded costs as follows.  First,
         for stranded costs associated with new wholesale requirements
         contracts (i.e., any wholesale requirements contract executed
         after July 11, 1994), the proposed regulations would allow
         recovery of stranded costs only if the contract explicitly
         provides for recovery of stranded costs.
              Second, for existing wholesale requirements contracts (i.e.,
         any wholesale requirements contract executed on or before July
         11, 1994), the proposed regulations would specify that a utility
         may not recover stranded costs associated with such contract if
         recovery is explicitly prohibited by the contract (including
         associated settlements) or by any power sales or transmission
         tariff on file with the Commission.  
              Third, for existing wholesale requirements contracts that do
         not address stranded costs through exit fee or other explicit
         stranded cost provisions, the proposed rule would allow a public
         utility to seek recovery of stranded costs only as follows:  (1)
         if the parties to the existing contract renegotiate the contract
         in accordance with this rule and file a mutually agreeable
         amendment dealing with stranded costs, and the Commission accepts
         Docket Nos. RM95-8-000
           and RM94-7-001              -200-
         or approves the amendment; (2) if either or both parties seeks an
         amendment to the existing contract under sections 205 or 206 of
         the FPA, prior to the date the contract expires, and the
         Commission accepts or approves an amendment permitting stranded
         cost recovery; or (3) if the public utility files a request,
         prior to the date the contract expires, to recover stranded costs
         through an adder to a departing customer's transmission rates
         under FPA sections 205-206, or 211-212.
              Fourth, if the selling utility under an existing wholesale
         requirements contract is a transmitting utility but not also a
         public utility, and the contract does not address stranded costs
         through an explicit exit fee or other stranded cost provision,
         the transmitting utility may seek to recover stranded costs
         through an adder to a departing customer's transmission rates
         under FPA sections 211-212.  Such utility may not seek recovery
         of stranded costs through a section 211-212 transmission rate if
         the existing contract does contain an explicit exit fee or other
         stranded cost provision.
              Fifth, for a retail-turned-wholesale customer, the proposed
         rule would allow a public utility or transmitting utility to file
         a request to recover stranded costs from the newly created
         wholesale customer through an adder to that customer's
         transmission rate.
              Sixth, for customers who obtain retail wheeling, a public
         utility or transmitting utility may seek recovery through
         Docket Nos. RM95-8-000
           and RM94-7-001              -201-
         transmission rates only if the state regulatory authority has no
         authority under state law at the time retail wheeling is required
         to address stranded costs.
                        (7)  Evidentiary Demonstration Necessary --
                             Reasonable Expectation Standard
              In the Stranded Cost NOPR, we proposed, as part of the
         evidentiary demonstration that a public utility or transmitting
         utility must make to recover stranded costs in wholesale
         transmission rates, or through a unilateral amendment to the
         power sales contract, that the utility must show that it incurred
         costs based on a reasonable expectation when the costs were
         incurred that the applicable contract would be extended. 283/
         We indicated that, in these situations, the question of whether a
         utility had a reasonable expectation of continuing to serve a
         customer is a factual matter that will depend on the evidence
         produced in each case.  We further proposed that a notice
         provision in a contract would create a rebuttable presumption
         that the utility had no reasonable expectation of serving the
         customer beyond the period provided for in the notice provision.
         We invited comments with regard to these proposals and also asked
         whether we should adopt a minimum notice period that would create
         a presumption that the utility had no reasonable expectation of
         continuing to provide service beyond such period (e.g., a five-

         283/ Stranded Cost NOPR at 32,873-74.
         Docket Nos. RM95-8-000
           and RM94-7-001              -202-
         year notice period). 284/
                             (a)  Comments
              Commenters express a variety of views on the reasonable
         expectation standard for extra-contractual cost recovery.  Some
         commenters (e.g., the Transmission Access Policy Study Group) do
         not believe there is a legal basis to permit the claimed
         expectation of indefinite renewal of a contract to override a
         customer's express contractual termination rights.  These
         commenters argue that there has never been any assurance that
         utilities will be allowed to recover all of their costs, no
         matter how incurred.  These commenters assert that utilities have
         been on notice for years that customers may try to exercise their
         contractual right to terminate service when their contracts end,
         and that utilities would not be entitled to any contract
         extensions or other relief.  These commenters state that the
         reasonable expectation test is an inadequate basis for denying
         customers their contractual termination rights.
              Other commenters (e.g., Environmental Action) state that if
         reasonable expectations (as opposed to contract language) are
         relevant, one must determine both the utility's and the
         customer's reasonable expectations.  These commenters support the
         concept of contract symmetry; if there is no obligation to serve
         beyond the contract term, imposing an obligation to pay beyond
         the contract term is asymmetrical.  

         284/ Id. at 32,874.
         Docket Nos. RM95-8-000
           and RM94-7-001              -203-
              With regard to the Commission's proposal that a notice
         provision in an existing contract creates a rebuttable
         presumption that there is no reasonable expectation that the
         contract will be renewed, many investor-owned utility commenters,
         as well as the Florida Commission and the Texas Commission,
         question whether a notice provision constitutes sufficient
         grounds for such an assumption.  Because of the obligation to
         serve and the long lead time needed to construct new base-load
         generating units, they argue that a utility could have been found
         to be imprudent if it did not plan for and build sufficient
         generating capacity to meet its service obligations.  These
         commenters maintain that it would have been unreasonable for a
         utility to assume that a customer that is served under a contract
         with a notice provision that has been repeatedly renewed would
         not again renew the contract.  These commenters maintain that a
         notice provision is not sufficient to demonstrate a "meeting of
         the minds" on this issue.
              TVA states that the notice provisions in its contracts in no
         way lessen its intention to serve its customers.  TVA states that
         its legislative provisions, planning process, and history all
         support the assumption that it will continue serving its
         wholesale customers indefinitely.
              Certain customer groups, such as the TDU Customers and the
         Wisconsin Wholesale Customers (Wisconsin Customers), believe that
         the Commission should make the rebuttable presumption stronger,
         Docket Nos. RM95-8-000
           and RM94-7-001              -204-
         i.e., that contracts with notice provisions should absolutely
         preclude stranded cost recovery.  Wisconsin Customers state that
         there should be no opportunity for renegotiation to include
         stranded cost provisions in contracts with reasonable notice
         provisions.
                             (b)  Preliminary Findings
              We believe we should retain a reasonable expectation
         standard as part of the evidentiary demonstration that a public
         utility or transmitting utility must make.  Whether a utility had
         a reasonable expectation of continuing to serve a customer, and
         for how long, will be determined on a case-by-case basis.
         Depending on all of the facts and circumstances, a reasonable
         expectation that a contract would be extended could be
         established, for example, by:  (1) whether the customer had
         access to alternative suppliers; (2) a showing that the parties'
         actual conduct or course of dealing has been to renew the
         contract upon its scheduled expiration; (3) evidence that a
         utility has recovered construction-work-in-progress (for projects
         that would enter service after the scheduled contract expiration)
         from a particular customer without the customer's objection; or
         (4) communications between supplier and customer concerning
         system planning, such as an indication by a buyer that the seller
         should continue to include the buyer's load in the seller's
         resource planning beyond the contract term. 285/

         285/ See id. at 32,874.
         Docket Nos. RM95-8-000
           and RM94-7-001              -205-
              In addition, as proposed in the initial NOPR, we believe
         that the existence of a notice provision in a contract should
         create a rebuttable presumption that the utility had no
         reasonable expectation of serving the customer beyond the period
         provided for in the notice provision.  Of course, evidence that a
         contract with a notice provision has been repeatedly renewed (the
         scenario described by commenters opposing the creation of a
         rebuttable presumption) may, depending on the particular case, be
         sufficient to rebut the presumption that the utility had no
         reasonable expectation of contract renewal.
              Further, we will not adopt a minimum notice period for
         purposes of applying the reasonable expectation rebuttable
         presumption.  We believe that whether a utility had a reasonable
         expectation of continuing to serve a customer, and for how long,
         including whether there is sufficient evidence to rebut the
         presumption that no such expectation existed beyond the notice
         provision in the contract, will depend on the facts of each case.
         In these circumstances, we do not believe that a generic minimum
         notice period would be appropriate.
              In addition, a contract that is extended or renegotiated for
         an effective date after July 11, 1994 becomes a new contract for
         which stranded cost recovery will be allowed only if explicitly
         provided for in the contract.
              We seek further comment on the following specific aspect of
         the reasonable expectation standard:  Should the reasonable
         Docket Nos. RM95-8-000
           and RM94-7-001              -206-
         expectation standard apply in a case where a utility has been
         making wholesale requirements sales to a customer in a non-
         contiguous service territory and where, in order to make such a
         sale possible, transmission service has been rendered by an
         intervening utility or utilities?  Should the Commission take
         this as conclusive evidence that the customer had a choice of
         wholesale suppliers and, therefore, that the seller had no
         reasonable expectation that the contract would be extended?  In
         the alternative, should the Commission choose to provide the
         seller with an opportunity to prove that it had a reasonable
         expectation, what weight should be given to the fact that
         transmission service was rendered by the intervening utility or
         utilities?  Finally, in the event that the seller establishes
         that it had a reasonable expectation, and the former wholesale
         customer does not take unbundled transmission service from the
         former seller, what means ought to be available for the
         collection of stranded costs?
                        (8)  Identification of Recoverable Wholesale
                             Stranded Costs
              The Stranded Cost NOPR proposed, as part of the evidentiary
         demonstration necessary for wholesale stranded cost recovery,
         that a utility show that the stranded costs it incurred are not
         more than the customer would have contributed to the utility had
         the customer remained a wholesale requirements customer of the
         utility.  We invited comments in the initial NOPR on what would
         constitute reasonable compensation for stranded costs and on how
         Docket Nos. RM95-8-000
           and RM94-7-001              -207-
         to determine the amount of stranded costs that the departing
         customer may be liable to pay.  For example, we asked whether it
         would be reasonable to limit the annual amount of stranded costs
         to what the departing customer would have contributed to the
         utility's capital (customer revenues minus variable costs), or
         whether an alternative concept would be appropriate.  We also
         requested comments as to what would constitute a "reasonable
         compensation period" over which to determine a customer's
         liability for stranded costs (e.g., five years, ten years, or
         some other period).  We indicated that the present value of the
         customer's liability could be the discounted value of an annual
         amount for such reasonable compensation period and that this
         total amount could be paid in a lump sum or over any mutually
         agreeable period. 286/
              We also assumed in the NOPR that stranded costs will be
         dominated by generating capacity, but stated that it is
         appropriate to consider stranded costs more broadly, including
         the possibility that fuel supply costs, purchased power costs
         (including QF costs), nuclear decommissioning costs, regulatory
         assets, and possibly other utility obligations may be stranded.
         Accordingly, we invited public comment on what categories of
         costs, in addition to investment costs, should be eligible for
         stranded cost recovery. 287/

         286/ Id. at 32,874-75.
         287/ Id. at 32,867.
         Docket Nos. RM95-8-000
           and RM94-7-001              -208-
                             (a)  Comments
                             (i)  Acceptable Calculation Methods
              Most commenters were not very specific regarding how to
         calculate the level of recoverable wholesale stranded costs.
         However, commenters that address this issue generally fall into
         three groups.
              The first group reflects the position of EEI and most
         investor-owned utility commenters.  This group proposes an asset-
         by-asset review of stranded investments (including contractual
         liabilities, regulatory assets, and certain social program costs)
         to develop a total company estimate of stranded costs that need
         to be recovered.  These costs could then be allocated among
         customers to determine a hypothetical cost-of-service measure of
         stranded cost liability.  From this amount, the utility would
         subtract wheeling service revenues and any revenues from
         mitigation measures taken.  As explained in more detail below in
         the discussion of allowable cost categories, investor-owned
         utility commenters argue for inclusion of a broad number of
         investments, expenses and future costs in the revenue requirement
         calculation of recoverable stranded costs.  Commenters that
         support this approach also suggest that costs are properly
         included in the calculation (i.e., are recoverable wholesale
         stranded costs) to the extent that such costs have been ruled to
         be prudently incurred in a state determination.
              Some commenters, however, oppose a hypothetical cost-of-
         Docket Nos. RM95-8-000
           and RM94-7-001              -209-
         service calculation approach to determining recoverable stranded
         costs arguing that it will engender litigation.  These commenters
         note that generating units are not built, and specific costs are
         not generally incurred, on behalf of individual customers.
         According to these commenters, attempting to define specific
         components of stranded costs associated with a specific departing
         customer is inconsistent with utility investment planning and
         historical cost incurrence.
              A second approach for determining recoverable wholesale
         stranded costs is based on "revenues lost" as a result of a
         customer switching suppliers.  Most non-investor-owned utility
         commenters (e.g., state commissions and customers) and some
         investor-owned utilities (e.g., Commonwealth Edison Company
         (Commonwealth Edison), Utility Working Group (UWG) 288/)
         support this method of calculation.  Commenters that support this
         approach argue that the calculation is less complex than a
         hypothetical cost-of-service approach and avoids an asset-by-
         asset review with its attendant accounting and tracking
         complexities.

         288/ The Utility Working Group members participating in UWG's
              comments in this proceeding are Dominion Resources, Inc.,
              Duke Power Company, Duquesne Light Company, Entergy
              Corporation, General Public Utilities Corporation, Niagara
              Mohawk Power Corporation, Northern States Power Company,
              Pacific Gas and Electric Company, Portland General Electric
              Company, Public Service Electric and Gas Company, San Diego
              Gas & Electric Company, Southern California Edison Company,
              and Wisconsin Electric Power Company.
         Docket Nos. RM95-8-000
           and RM94-7-001              -210-
              Many commenters note that the revenues lost approach
         recognizes that utilities that made multiple investment decisions
         under the prior regulatory scheme compact expected a revenue
         stream from their customers to cover the costs of those
         investments.  Under this approach, the measure of recoverable
         stranded costs is the difference between revenues expected from a
         customer under traditional regulation and the expected revenues
         in a competitive market.  Some commenters suggest further
         limitations on the revenue stream calculation, i.e., calculating
         revenues on a present value basis, or using current revenues as
         the ceiling for utility expected revenues under the prior
         regulatory regime.  According to commenters, these limitations
         serve at least two purposes:  (1) simplifying the calculation;
         and (2) creating incentives for utilities to mitigate stranded
         costs, which will shorten the transition period to a competitive
         market.
              Some commenters, including Public Service Electric and Gas
         Company (Public Service Electric), also point out that this
         approach is consistent with resource acquisition.  These
         commenters note that specific investment decisions are not made
         on a retail/wholesale or customer-by-customer basis, but rather
         on the basis of resources needed to meet load, i.e., generation
         plant additions are made based on an analysis of total system
         needs.  Commenters also note that under a revenues lost approach,
         specific investments/assets do not need to be assigned (or
         Docket Nos. RM95-8-000
           and RM94-7-001              -211-
         tracked) to a particular event causing stranded costs.
              A few commenters (e.g., APPA, Electric Generation
         Association, Illinois Commission) advocate a third method of
         calculating the level of recoverable wholesale stranded costs.
         Under this method, which is a "netting" or "market analysis"
         approach, recoverable stranded costs would be determined based on
         the difference between embedded capital costs and the market
         value of stranded assets.  While this approach is not dissimilar
         to a "revenues lost" approach, the level of stranded costs is
         generally determined only after a future action with respect to
         the stranded costs, i.e., auction, divestiture or other future
         disposition of assets.  Other commenters (e.g., Central Vermont
         Public Service Corporation, Long Island Lighting Company (Long
         Island Lighting)) suggest variations of this "netting" approach,
         such as comparing the utility's revenues with some measure of the
         utility's marginal cost of requirements service.  Commenters
         claim that, in a competitive market, the marginal cost would
         equal the market price.  Thus, under this approach, recoverable
         stranded costs are the excess above market value of the stranded
         assets.  Duke Power Company notes that mitigation measures would
         be unnecessary if this method were used to calculate recoverable
         stranded costs because the utility's marginal cost (not just its
         variable expenses), i.e., the market price of the stranded
         assets, is used as the "offsetting" value in the calculation.
         Docket Nos. RM95-8-000
           and RM94-7-001              -212-
                             (ii) Reasonable Compensation Period (how long
                                  utility could reasonably expect to keep
                                  customer)
              Commenters support a wide range of time periods as
         appropriate for determining a customer's stranded cost liability.
         Almost all of the commenters, however, request that the
         Commission provide flexibility in this regard and not establish a
         generic recovery period so that a variety of recovery mechanisms
         can be accommodated.
              Some state commission commenters (e.g., Illinois Commission)
         support a limited time period for determining a customer's
         stranded cost liability as an incentive for utilities to mitigate
         stranded costs.  According to the Illinois Commission, limiting
         the time period over which a customer's stranded cost liability
         is to be determined should encourage utilities to "fervently re-
         market the services produced by the potentially stranded
         resources." 289/  Utility customer commenters (e.g., City of
         Las Cruces, TDU Customers) also support a limitation on the
         period over which stranded costs would be determined.  These
         commenters propose limiting the reasonable compensation period to
         the lesser of the contractual notice period; the remaining
         portion of the stated term of a contract; a five-year period (as
         a maximum reasonable time to plan for mitigation measures); or
         the utility's planning horizon.

         289/ Illinois Commission comments at 61-62.
         Docket Nos. RM95-8-000
           and RM94-7-001              -213-
              Some investor-owned utility commenters (e.g., EEI, Centerior
         Energy Corporation), on the other hand, oppose limiting the
         period over which a customer's stranded cost liability would be
         determined.  EEI, for example, states that as a general rule, the
         departing customer should be responsible for its regulated rate
         less the utility's marginal cost and mitigating revenue.  It
         contends that the period of such responsibility should continue
         until the utility needs the capacity freed up by the departing
         customer to meet retail load growth or firm wholesale
         obligations.  In effect, these commenters support an open-ended
         opportunity to recoup wholesale stranded costs.  They argue that
         the recovery period should continue as long as possible to ensure
         that native load customers are held harmless.
                             (iii)  Allowable Cost Categories
              Almost all commenters agree that stranded costs should not
         include variable expenses.  The majority of customer commenters
         either:  (1) support the Commission's proposed categories; or (2)
         do not express an opinion regarding cost categories that are
         appropriate for recovery because they support the use of some
         type of "revenues lost" approach for determining recoverable
         costs, which does not require the identification of specific
         utility investments or expenses.
              Many investor-owned utility commenters, however, contend
         that, in addition to the items identified in the NOPR,
         recoverable stranded costs should include a broad number of other
         Docket Nos. RM95-8-000
           and RM94-7-001              -214-
         investments, expenses and future costs.  These commenters propose
         that the additional items that are eligible for recovery should
         include, but not be limited to:
              °    construction work in progress;
              °    regulatory assets, such as phase-in plans for new
                   generation plant, and accrual accounting requirements
                   (e.g., income tax normalization, accounting for pension
                   and PBOP costs);
              °    actual nuclear decommissioning costs as well as a
                   utility's pro rata obligation to dismantle and
                   decontaminate DOE's uranium enrichment facilities;
              °    all fuel costs pending recovery via fuel adjustment
                   mechanisms;
              °    mandatory social program costs including DSM, low-
                   income assistance, environmental clean-up and various
                   R&D projects;
              °    Clean Air Act compliance costs;
              °    storm damage expenses; and
              °    other unknown future liabilities.
              In addition, EEI states that before 1992, i.e., pre-EPAct,
         no regulatory commission explicitly authorized a rate of return
         that compensated a utility for the risk of future retail
         competition.  EEI notes that after EPAct only four regulatory
         commission decisions have addressed this issue.  Because the
         risks of the new competitive market were neither contemplated by
         Docket Nos. RM95-8-000
           and RM94-7-001              -215-
         investors nor compensated by regulators under existing
         ratemaking, EEI argues that the cost of such risk must also be
         included as a category of costs eligible for stranded cost
         recovery.
              Public Power Council suggests that there are two dangers in
         creating lists of eligible and ineligible costs:  (1) wasteful
         regulatory battles are likely; and (2) utility managers will have
         the incentive to reduce ineligible costs, while ignoring
         opportunities to reduce eligible costs.
                             (b)  Preliminary Findings
              The Commission preliminarily concludes that the
         determination of recoverable stranded costs should be based on a
         "revenues lost" approach rather than a hypothetical cost-of-
         service approach.  The Commission believes that this approach has
         greater benefits than a hypothetical cost-of-service approach.  A
         "revenues lost" approach avoids the asset-by-asset review that is
         required by alternative cost-of-service approaches in order to
         calculate recoverable stranded costs.  Cost allocation procedures
         are also minimized.  Moreover, the Commission believes that this
         approach will be easier to apply, thereby minimizing the cost of
         administering stranded cost recovery.
              The Commission's experience in the natural gas industry is
         relevant here.  Certain pipelines faced with take-or-pay
         obligations under uneconomic natural gas supply contracts have
         developed a "pricing differential" mechanism that has enabled
         Docket Nos. RM95-8-000
           and RM94-7-001              -216-
         them to honor existing take-or-pay obligations, while attempting
         to renegotiate the contracts. 290/  Under this mechanism, the
         pipeline continues to meet its contractual purchase obligation
         and continues to market the gas purchased through its separate
         marketing operation.  The "differential" or "revenues lost"
         between the purchase price and the sales price is passed through
         as a transition cost. 291/
              Under the revenues lost method that we propose here, the
         utility would calculate a customer's stranded cost liability by
         subtracting the competitive market value of the power the
         customer would have purchased from the utility (and the basic
         revenues from the transmission service) had the customer
         continued to take service under its contract from the revenues
         that the customer would have paid the utility.  As discussed in
         section III.F.1.c(9) infra, the utility must attempt to mitigate
         stranded costs by marketing stranded power supplies.
              The Commission seeks further comments on the revenues lost
         approach.  In particular, what would be the appropriate method to
         calculate what the utility's revenue stream would have been had
         the customer continued service (e.g., current revenues based on
         current service levels, or should projection and adjustments

         290/ Texas Eastern Transmission Corporation, 63 FERC ¶ 61,100 at
              61,507 (1993).
         291/ For details on the mechanics of this program, see Texas
              Eastern Transmission Corporation, 63 FERC at 61,507-08;
              Texas Eastern Transmission Corporation, 64 FERC ¶ 61,378
              (1994).
         Docket Nos. RM95-8-000
           and RM94-7-001              -217-
         reflecting changes in the revenue stream be permitted)?  The
         Commission also seeks comments on the appropriate method to
         calculate the revenues that the utility would receive in a
         competitive market for the stranded assets.  Should the
         Commission require the utility to track the actual selling price
         of the power over time, or should it require the utility to use
         an up-front approach, such as an estimate of the forecasted
         market value of the power for the period during which the
         customer would have taken service?  Should the Commission allow
         prices in futures markets or forward markets to be used in an up-
         front approach, assuming such financial instruments become
         available?  In addition, how should revenues received as a result
         of mitigation measures be reflected in the determination of the
         amount of recoverable stranded costs?  What special accounts, if
         any, should be created to track revenue liability for specific
         customers, revenues from mitigation measures, and other revenues
         received by the utility that offset the stranded cost liability?
         Once determined, should any adjustment be permitted to the
         revenues that the utility claims will be realized in a
         competitive market for its stranded assets, and if so, how often
         and under what circumstances?
              With regard to establishing a reasonable compensation period
         (i.e., setting a limit on how long the utility could have
         reasonably expected to keep the customers), we do not believe
         that a one-size-fits-all approach is appropriate.  A particular
         Docket Nos. RM95-8-000
           and RM94-7-001              -218-
         customer's stranded cost liability will depend, in each instance,
         on such case-specific factors as whether the utility can
         demonstrate that it had a reasonable expectation of continuing to
         serve the customer beyond the term of the contract and, if so,
         for how long.  Therefore, we believe it appropriate to permit
         utilities and their customers some flexibility with regard to the
         period over which a customer's stranded cost liability would be
         determined.  However, we will not allow an open-ended opportunity
         to recoup wholesale stranded costs.  Although our preliminary
         finding is that a one-size-fits-all approach is not appropriate,
         we seek further comment with respect to whether the Commission
         ought to establish presumptions or, in the alternative, absolute
         limits on a customer's maximum liability in those situations
         where a utility establishes that it had a reasonable expectation
         that the contract would be extended.  For instance, would it be
         appropriate to pick an outer limit equal to the revenues that the
         utility would lose during the length of one additional contract
         extension period, or during the length of the utility's planning
         horizon?  What other events or criteria might the Commission use
         to establish either presumptions or absolute limits on the time
         period over which the customer's liability for stranded costs
         would be determined?
              Our decision to adopt a revenues lost approach for
         determining recoverable stranded costs, which avoids an asset-by-
         asset review, in effect eliminates the need to enumerate specific
         Docket Nos. RM95-8-000
           and RM94-7-001              -219-
         categories of costs that may be recovered.  However, there may be
         special categories of costs that are properly allocated to
         departing customers and that are not captured in the revenues
         lost approach.  For example, nuclear decommissioning costs may
         not be reflected, or may not be fully reflected, in current
         requirements rates.  To the extent this is true, a departing
         customer may be "escaping" from costs that it caused as a result
         of taking power service from its supplier during the time that
         the nuclear plant was operating.  We seek comments on whether
         there are special costs that warrant some special consideration
         in the determination of stranded cost liability under a revenues
         lost approach, and if so, how they should be treated.  We also
         solicit comments as to whether the Open Access NOPR raises any
         additional implementation or other issues affecting stranded cost
         recovery as proposed here.
                             (9)  Mitigation Measures
              As part of the evidentiary demonstration that a utility must
         make in order to recover stranded costs, the Stranded Cost NOPR
         would require the utility to show that it has taken and will take
         reasonable and prudent measures to mitigate stranded costs.  The
         Commission proposed in the initial NOPR that adequate mitigation
         measures might include:  (1) evidence that the utility has tried
         to market the asset or assets, market the generating capacity,
         reconfigure or delay investment in or purchase of new generating
         capacity, or reform fuel supply contracts that form the basis for
         Docket Nos. RM95-8-000
           and RM94-7-001              -220-
         the stranded costs charge, and that such measures to mitigate
         stranded costs will continue for the entire period for which the
         stranded costs charge will be paid; or (2) the utility has given
         the customer the option to market the generating capacity or
         supply of fuel or purchased power that forms the basis for the
         stranded cost charge in order to afford the customer an
         opportunity to lower its stranded costs charge.  We invited
         comment on the mitigation requirement and what reasonable
         measures to mitigate may include.
                             (a)  Comments
              Although there is nearly unanimous support for requiring
         that mitigation measures be taken, commenters raise several
         issues regarding how mitigation should be implemented and the
         effectiveness of such a requirement.
              As noted above, many investor-owned utility commenters argue
         that stranded costs should be defined to include costs other than
         capital investment in utility property.  According to these
         commenters, stranded costs also may include environmental clean-
         up costs, decommissioning costs, and regulatory assets resulting
         from cost recovery deferrals.  Unlike capacity, these costs
         cannot be "marketed."  Therefore, mitigation measures cannot be
         taken with respect to these costs.  Thus, according to some
         commenters, there is a category of "unmarketable" stranded costs
         for which mitigation efforts to reduce the level of the costs are
         not possible.
         Docket Nos. RM95-8-000
           and RM94-7-001              -221-
              Many commenters (e.g., Texas Commission, TDU Customers)
         contend that a mitigation requirement will be more effective if
         incentives to mitigate are created.  These commenters suggest
         several options, including:
              °    limiting recovery of stranded costs to current rate
                   levels (no projections of increases in stranded costs
                   for future periods);
              °    requiring shareholders to shoulder some cost
                   responsibility (to ensure that mitigation measures will
                   be aggressively pursued); and
              °    requiring any stranded investment to be offered for
                   sale, either with the departing customer permitted to
                   "sell" the stranded investment, or through some form of
                   auction.
              Other commenters suggested that effective mitigation would
         require auctioning off stranded assets or some type of general
         divestiture of assets by the utility that is allowed to recover
         stranded costs.
              Many commenters acknowledge that revenues from mitigation
         measures should reduce the amount of wholesale stranded costs.
         An issue is raised, however, regarding how revenues associated
         with mitigation measures should be credited.  Given the overall
         preference by commenters supporting stranded cost recovery for
         direct assignment of stranded costs to a departing customer,
         explicit crediting mechanisms and accounting requirements -- and
         Docket Nos. RM95-8-000
           and RM94-7-001              -222-
         perhaps new accounts or subaccounts -- would be needed to keep
         track of amounts owed by those assessed wholesale stranded costs.
         Consequently, these commenters contend that decisions regarding
         who should pay (and how) for wholesale stranded costs must be
         coordinated with decisions regarding the implementation of
         required mitigation measures so that parties receive appropriate
         credits.
                             (b)  Preliminary Findings
              We note that the revenues lost approach for determining
         recoverable stranded costs encompasses mitigation measures
         because it reduces the amount of stranded costs recoverable by a
         utility by the market price of the power that the customer no
         longer takes under its contract.  Thus, our suggestion in the
         initial NOPR that revenues associated with mitigation measures be
         credited to the departing customer through reductions to that
         customer's surcharge is in effect accomplished by adoption of the
         revenues lost approach.  This is particularly so if mitigation is
         reflected through a one-time, up-front estimate of the future
         market value of the power, and is not trued-up over time.
         Nonetheless, we emphasize that mitigation as a general matter
         remains important, and seek comment regarding implementation of a
         mitigation requirement.  For example, if mitigation is trued-up
         over time, how should the Commission ensure that the utility
         takes all reasonable steps to mitigate its own costs so as to
         minimize what the customer would have paid?  How should the
         Docket Nos. RM95-8-000
           and RM94-7-001              -223-
         Commission ensure that the utility does its best to sell the
         power at its highest possible value so as to mitigate the
         customer's stranded cost liability?  Are there other mitigation
         measures that should be taken into account (e.g., efficiency
         improvements that a utility would have undertaken regardless of
         whether the particular customer continued to take power under its
         contract, or cost savings resulting from the buy-out of a fuel
         contract made possible by the customer's departure)?
                        (10) Federal Forum for "Retail" Stranded Cost
                             Recovery and Proposed New Definition of
                             "Wholesale" Stranded Costs
              In the initial NOPR, the Commission described two general
         ways in which retail stranded costs are likely to occur:  (1) a
         retail franchise customer or group of such customers may, through
         state or local government action, become a wholesale customer
         that can then obtain unbundled transmission services in order to
         reach a new power supplier; and (2) a retail franchise customer
         may obtain voluntary unbundled retail transmission services from
         its existing power supplier in order to reach a new power
         supplier, or there may be a State or local government action that
         results in the existing supplier providing such retail
         transmission services.  The Commission requested comments
         concerning the extent to which the Commission should provide a
         forum for resolving retail stranded cost issues.  The Commission
         proposed two alternatives for addressing this issue.  Under the
         first alternative, the Commission proposed that it would not
         Docket Nos. RM95-8-000
           and RM94-7-001              -224-
         entertain a request for retail stranded cost recovery if, in a
         specific circumstance, an appropriate state authority explicitly
         considers and deals with retail stranded costs and there is no
         conflict within or among state regulatory bodies regarding a
         state's disposition of the issue.  However, in the absence of a
         clear expression by an appropriate state authority that it has
         dealt with the issue, or in the event of a conflict between
         states or among state officials within a single state, the
         Commission proposed to entertain requests to recover retail
         stranded costs.  Under the second alternative, the Commission
         proposed not to entertain any request for recovery of retail
         stranded costs.  Under this alternative, we proposed that state
         or local authorities would be the only forum for addressing the
         issue. 292/
                             (a)  Comments
              Most of the state commissions comment that the Commission
         should not provide a forum for addressing retail stranded cost
         issues.  The Massachusetts Department of Public Utilities
         suggests Commission involvement only if a conflict arises through
         disparate stranded cost treatment by different states that the
         states are unable or unwilling to resolve.  The Pennsylvania
         Commission suggests Commission involvement in retail stranded
         cost issues only if states have lost jurisdiction (for instance,
         due to municipalization).  Most of the state commissions argue

         292/ Stranded Cost NOPR at 32,878-79.
         Docket Nos. RM95-8-000
           and RM94-7-001              -225-
         that retail costs are subject to exclusive state jurisdiction and
         that action or inaction by a state or any differences between
         state actions are matters to be resolved by the courts, not the
         Commission.  Many of these commenters (e.g., NARUC) note that
         numerous differences in ratemaking currently exist among states
         and that the Commission has not attempted to resolve those
         differences; they see no distinction with regard to retail
         stranded cost recovery.  Some state commissions also argue that
         the possibility of Commission involvement in retail stranded cost
         recovery could introduce "forum shopping."
              The New York State Public Service Commission (New York
         Commission) suggests that the Commission provide a backstop to
         the states only if a state has taken no action regarding retail
         stranded costs.  The Ohio Public Utilities Commission (Ohio
         Commission) and the Wyoming Public Service Commission suggest
         that the Commission become involved in retail stranded costs only
         at the request or petition of a state.  Commenters representing
         investor-owned utilities, on the other hand, overwhelmingly agree
         that the Commission should provide a forum for resolving retail
         stranded cost issues.  They propose a broad range of scenarios in
         which Commission involvement in retail stranded cost recovery is
         appropriate.
              EEI, Commonwealth Edison, Florida Power and Northern States
         Power Company argue that the Commission should act as a backstop
         to state commissions with authority to address retail stranded
         Docket Nos. RM95-8-000
           and RM94-7-001              -226-
         cost issues:  (1) to address yet undefined questions; (2) when no
         state commission action is taken; or (3) when state commission
         action is not taken in a fair and timely manner or results in the
         confiscation of utility property.
              Allegheny Power, Arizona Public Service Company and Virginia
         Electric and Power Company argue that the Commission should
         provide a forum to address situations in which states allegedly
         have no authority to address retail stranded cost issues
         (primarily municipalization).
              The Coalition for Economic Competition, Entergy, Utility
         Working Group, and the Nuclear Energy Institute urge the
         Commission to address situations in which state policy is
         inconsistent with Commission policy.  In fact, many investor-
         owned utilities advocate the establishment of uniform national
         guidelines for stranded cost recovery that will be applicable to
         both wholesale and retail stranded costs.  These commenters
         contend that the Commission is the only body capable of
         fulfilling this role.
              Houston Lighting & Power Company urges the Commission to
         address retail stranded costs whenever retail stranded costs have
         a substantial adverse impact on interstate transmission.
              Two investor-owned utilities support Commission involvement
         in retail stranded cost issues only in limited circumstances.
         Entergy contends that Commission involvement is necessary only if
         state jurisdiction is evaded (i.e., certain cases of
         Docket Nos. RM95-8-000
           and RM94-7-001              -227-
         municipalization).  Public Service Electric states that
         Commission oversight is needed to ensure that final results are
         consistent with Commission guidelines and are pro-competitive.
              Commenters representing small customer interests, such as
         Electric Consumers' Alliance and the National Black Caucus of
         State Legislators, support Commission involvement in retail
         stranded cost issues in order to ensure that large customers that
         leave the system do not evade their fair share of stranded costs
         to the detriment of residential and other small customers.
              Commenters representing municipal and electric cooperatives
         (such as APPA, TAPS and SCOOP), commenters representing
         independent power producers (such as the National Independent
         Energy Producers), commenters representing industrial customers,
         some customer advocacy group commenters (such as Industrial
         Consumers, American Forest, and the National Association of State
         Utility Consumer Advocates (NASUCA)), and commenters representing
         environmental groups (such as CLF) generally oppose Commission
         involvement in retail stranded cost issues.
              DOE agrees with the Commission that retail stranded cost
         recovery is primarily a state issue.  However, DOE states that
         the Commission has correctly determined that it has authority to
         regulate the rates, terms and conditions of retail transmission
         service.  Accordingly, DOE supports Commission involvement in
         retail stranded cost issues.
              DOE notes that states may decide to make retail competition
         Docket Nos. RM95-8-000
           and RM94-7-001              -228-
         contingent upon the recovery of stranded costs by their
         jurisdictional utilities.  DOE states that the Commission does
         not appear to have considered the possibility that a utility may
         seek recovery of retail-related stranded costs through a retail
         transmission tariff filed with this Commission that has the
         support of the state commission.  DOE submits that the
         Commission, as a matter of policy, should allow utilities to file
         tariffs for retail transmission service that recover stranded
         retail costs when such filings have the support of the affected
         state commissions.  However, DOE states that the Commission
         should not give deference to tariffs for retail transmission
         service that contain a provision for stranded cost recovery if
         the tariff is opposed by any state commission that has a material
         interest in the filing.
              Public Service Electric states that due to the vertical
         integration of electric utilities, the distinction between
         wholesale and retail stranded costs is merely a matter of cost
         allocation.  It contends that utilities generally do not have
         specific generating facilities in place to serve strictly
         wholesale customers, but rather include wholesale customer loads
         into their planning models as if they were retail customers.
         Public Service Electric thus concludes that no distinction
         between wholesale and retail stranded costs is necessary for
         purposes of evaluating stranded cost recovery.
         Docket Nos. RM95-8-000
           and RM94-7-001              -229-
              In contrast, other commenters contend that there are
         inherent differences between retail and wholesale stranded costs,
         resulting primarily from the different regulatory regimes in
         place.  These commenters state that, at the state level, a
         utility provides retail service pursuant to a "regulatory
         compact" under which the utility undertakes an obligation to
         serve retail customers in exchange for an exclusive service
         franchise.  In contrast, they submit that the utility's
         obligation to serve a customer at the wholesale level is
         established through contract.  Some commenters conclude that
         these differences necessitate different approaches for recovery
         of wholesale and retail stranded costs.
              Several commenters (e.g., Duke, Entergy, Long Island
         Lighting, Nuclear Energy Institute, 293/ Public Service
         Electric, Coalition for Economic Competition, Utility Working
         Group) request that the Commission issue a uniform national set
         of standards to govern the treatment of all stranded investment
         (both retail and wholesale), irrespective of jurisdiction with
         respect to retail stranded costs.
              In contrast, several of the state commission commenters
         emphasize a need for flexibility in dealing with retail stranded
         costs in lieu of a one-size-fits-all solution, which they argue
         may fail to address important differences between states.

         293/ Nuclear Energy Institute's utility members operate all (109)
              of the nuclear power plants in the United States.
         Docket Nos. RM95-8-000
           and RM94-7-001              -230-
         Accordingly, several of the state commission commenters,
         including the Alabama, California, Indiana, Michigan, and New
         York Commissions, urge that the Commission develop in cooperation
         with the state commissions a flexible approach to retail stranded
         cost recovery through various means such as joint boards or
         through more informal conferences or other joint forums.
              With respect to the issue of stranded costs caused by
         retail-turned-wholesale customers, EEI and several investor-owned
         utilities (particularly those in Michigan, New York and
         California) maintain that the most important stranded cost issue
         before the Commission at this time is the formation of new
         municipal utilities.  These commenters urge Commission
         involvement in the recovery of stranded costs resulting from this
         action.  EEI notes that most states have constitutions or laws
         that permit municipalization, through which groups of retail
         customers may, in effect, become wholesale customers and thereby
         transfer primary regulatory responsibility for regulating sales
         to such entities from a state commission to the Commission.
              EEI argues that in most instances the Commission will be the
         regulatory body that will have to consider stranded cost recovery
         issues resulting from municipalization.  EEI states that in
         approximately 28 states, there is virtually no limitation on the
         ability of municipalities to form utilities or to oust current
         Docket Nos. RM95-8-000
           and RM94-7-001              -231-
         suppliers; 294/ these states will be unable to protect their
         utilities from stranded costs.  According to EEI, only 14 state
         commissions have some jurisdiction over the creation or expansion
         of municipal utilities, 295/ and only a few states require
         reimbursement for stranded generation or for lost earnings.
         Moreover, EEI notes that condemnation proceedings based on
         eminent domain principles often do not consider regulatory
         policies regarding stranded cost assignment and recovery.
              NARUC, on the other hand, argues that states and/or state
         commissions have the ability to address all retail stranded cost
         issues.  From NARUC's perspective, the recovery of stranded costs
         due to municipalization is a matter to be addressed by state
         authorities.  Appendix D to NARUC's comments contains information
         regarding state practices and policies in the areas of
         municipalization and newly-municipalized service territory (i.e.,
         annexation).  While policies do vary among the states, NARUC as
         well as most state commission commenters (e.g., Iowa Commission)
         maintain that state authorities (commissions, courts and
         legislative bodies) clearly have the ability to impose stranded

         294/ EEI states that these states are Arizona, Connecticut,
              Delaware, Florida, Georgia, Idaho, Illinois, Kansas,
              Kentucky, Louisiana, Michigan, Minnesota, Montana, Nevada,
              New Jersey, New  Mexico, New York, North Dakota, Ohio,
              Oklahoma, Oregon, Rhode Island, South Dakota, Tennessee,
              Utah, Virginia, Washington and Wyoming.
         295/ EEI states that these states are Alaska, Arkansas, Iowa,
              Indiana, Maryland, Massachusetts, North Carolina, New
              Hampshire, South Carolina, South Dakota, Texas, Vermont,
              West Virginia and Wisconsin.
         Docket Nos. RM95-8-000
           and RM94-7-001              -232-
         asset payments on new municipal utilities.  NARUC contends that
         resolution by state authorities is mandated by the legal
         authority of the states to act, and does not depend upon
         Commission deference to the states.  NARUC also cautions the
         Commission against becoming an appellate body for reviewing state
         determinations that allegedly overrecover or underrecover
         stranded costs.
              However, NARUC suggests two situations where Commission
         involvement with stranded cost recovery in a municipalization
         scenario is reasonable.  The first case is when a state
         determines that the appropriate cost recovery mechanism would
         involve a wholesale transmission rate beyond the state's
         jurisdiction.  The second case is when the sequence of events or
         the timing of the transaction creates some ambiguity regarding
         the retail or wholesale character of the costs (e.g., the
         Massachusetts Bay Transit Authority case cited in the NOPR).
              Some commenters (e.g., Florida Commission) request joint
         federal/state consultation on the issue of municipalization.  The
         Florida Commission also requests that the Commission delay the
         effectiveness of wholesale contracts resulting from
         municipalization until retail stranded cost issues are resolved.
                             (b)  Preliminary Findings
              As discussed in the initial NOPR, as a general matter we
         believe that both this Commission and state commissions have the
         legal authority to address stranded costs that result from retail
         Docket Nos. RM95-8-000
           and RM94-7-001              -233-
         customers becoming wholesale customers who then obtain wholesale
         wheeling, or from retail customers who obtain retail wheeling, in
         order to reach a different generation supplier.  Based on an
         analysis of all the comments received, we propose to exercise our
         authority to address stranded costs as follows.   
              Because the vast majority of commenters have urged the
         Commission not to assume responsibility for retail stranded
         costs, except in certain circumstances, we have concluded that it
         is appropriate to leave it to state regulatory authorities to
         deal with any stranded costs occasioned by retail wheeling.  The
         circumstances under which we will entertain requests to recover
         stranded costs caused by retail wheeling are when the state
         regulatory authority does not have authority under state law to
         address stranded costs at the time the retail wheeling is
         required.  We continue to believe that utilities are entitled,
         from both a legal and policy perspective, to an opportunity to
         recover all of their prudently incurred costs.  In addition, as
         discussed further below, we believe the Commission should be the
         primary forum for addressing recovery of stranded costs caused by
         retail-turned-wholesale customers.   
              With regard to stranded costs caused by retail wheeling, we
         emphasize that we will not allow states to use the interstate
         transmission grid as a vehicle for passing through any retail
         stranded costs, with the limited exception discussed above.  Only
         if the state regulatory authority does not have authority under
         Docket Nos. RM95-8-000
           and RM94-7-001              -234-
         state law at the time the retail wheeling is required to resolve
         the retail stranded cost issue will we permit a utility to seek a
         customer-specific surcharge to be added to an unbundled
         transmission rate.  We have accepted the view that stranded costs
         caused by retail wheeling are primarily a matter of local or
         state concern.  Thus, these costs generally must be passed
         through in a manner that does not involve "transmission of
         electric energy in interstate commerce" as that phrase is used in
         the FPA.  We are proposing to prohibit the pass-through of these
         costs on interstate transmission facilities except in the limited
         circumstance described.  As discussed in section III.F.1.c(11),
         we believe that most states have a number of mechanisms for
         addressing stranded costs caused by retail wheeling, as well as
         retail-turned-wholesale customers.  In addition, as further
         discussed in section III.F.1.c(12), we are proposing to define
         "facilities used in local distribution" under section 201(b)(1)
         of the FPA.  Rates for services using such facilities to make a
         retail sale are state-jurisdictional.  States therefore will be
         free to impose stranded costs caused by retail wheeling on
         facilities or services used in local distribution.
              At this juncture, the Commission is comfortable with this
         approach and our hope is that a federal forum for recovery of
         retail stranded costs ultimately will not be necessary.  When
         states address retail stranded costs caused by retail wheeling,
         the Commission holds the strong expectation that states will
         Docket Nos. RM95-8-000
           and RM94-7-001              -235-
         provide procedures for, and the full recovery of, legitimate and
         verifiable stranded costs.  This is the same standard we set out
         for wholesale stranded costs.  We do so as part of our goal to
         assure a smooth and orderly industry transition to competition
         that is fair to all affected parties.  In this proposal we also
         set out procedures that all parties can use to seek equitable
         treatment of stranded cost recovery.  Again, we expect a state
         providing for direct access to provide similar procedures.  We
         know that states are aware and concerned about the impacts of
         providing direct access as shown by many state comments.  Based
         on this awareness and concern, we anticipate state approaches to
         retail stranded costs not unlike our approach to wholesale
         stranded costs.  Although our hope is that a federal forum will
         not be necessary, we will watch with interest the states' efforts
         to address the retail stranded cost problem.
              We believe this approach represents an appropriate balance
         between federal and state interests.  It ensures that the
         wholesale market, except in a narrow circumstance, will not be
         burdened by retail costs.  It also helps to ensure that one state
         will not be able to burden customers in another state with
         stranded costs due to retail wheeling.
              We have a different view with regard to stranded costs
         caused by retail-turned-wholesale customers.  If a retail
         customer becomes a legitimate wholesale customer, e.g., through
         municipalization, it would thereby become eligible to use the
         Docket Nos. RM95-8-000
           and RM94-7-001              -236-
         non-discriminatory open access tariffs we are proposing to
         require public utilities to provide.  If costs are stranded as a
         result of this wholesale transmission access, we believe that
         these costs should be viewed as "wholesale stranded costs."  But
         for the ability of the new wholesale entity to reach another
         generation supplier through the FERC-filed open access
         transmission tariff, such costs would not be stranded.  While the
         stranded costs likely would derive primarily from generation
         investments that previously were in retail rate base, we note
         that utilities generally build generating facilities and incur
         other costs to serve their entire load, both retail and
         wholesale.  We believe that costs stranded by the departure of a
         retail-turned-wholesale customer could and should be considered
         FERC-jurisdictional stranded costs once the new wholesale
         customer begins taking wholesale transmission services.  They are
         identifiable economic costs that were incurred by the
         jurisdictional transmitting utility, and they do not disappear
         simply because the identity of the customer changes from retail
         to wholesale.  There is a clear nexus between the FERC-
         jurisdictional transmission and the exposure to non-recovery of
         prudently incurred costs.  Accordingly, we believe this
         Commission should be the primary forum for addressing recovery of
         such costs.  To avoid forum shopping and duplicative litigation
         of the issue, we expect parties to raise claims before this
         Commission in the first instance.  
         Docket Nos. RM95-8-000
           and RM94-7-001              -237-
              To implement this policy, we propose to change the
         definition of "wholesale stranded costs" that was contained in
         the initial NOPR, and to propose a definition that includes
         stranded costs resulting from unbundled wholesale transmission
         for newly created wholesale customers.  We seek comment on this
         proposed change.
              We propose to require the same evidentiary demonstration for
         recovery of stranded costs from a retail-turned-wholesale
         customer or a retail customer that obtains retail wheeling as
         that required when wholesale requirements customers leave a
         utility's system.  In this regard, we no longer propose to adopt
         the proposal in the initial NOPR that the "reasonable
         expectation" test should not apply in the case of retail-turned-
         wholesale customers or retail customers that obtain retail
         wheeling. 296/  We propose that the utility must demonstrate
         that it incurred stranded costs based on a reasonable expectation
         that the customers would continue to receive bundled retail
         service.  We expect that the reasonable expectation test would be
         easily met in those instances in which state law awards exclusive
         service territories and imposes a mandatory obligation to serve.
         297/  We solicit comments on this proposed change.
              We reaffirm our proposal in the initial NOPR that utilities

         296/ Stranded Cost NOPR at 32,879.
         297/ We note, however, that certain states do not have service
              territories or have non-exclusive service territories (e.g.,
              Louisiana).
         Docket Nos. RM95-8-000
           and RM94-7-001              -238-
         will have to make an evidentiary showing that the stranded costs
         are not more than the net revenues that retail-turned-wholesale
         customers or retail customers that obtain retail wheeling would
         have contributed to the utility had they remained retail
         customers of the utility, and that it has taken and will take
         reasonable steps to mitigate stranded costs.  If the state has
         permitted any recovery from departing retail-turned-wholesale
         customers, we will deduct that amount from what we determine to
         be legitimate stranded costs for which we will allow recovery.
              The procedures that we propose for a wholesale customer to
         file with the public utility when it requests computation of its
         stranded cost exposure will apply with equal force to a retail
         customer contemplating becoming a wholesale transmission customer
         (e.g., through municipalization).  In particular:
              (1)  Such a retail customer or group of customers may, at
                   any time, request the public utility to either:  (i)
                   calculate its maximum possible stranded cost exposure
                   without mitigation, as of the date set forth in the
                   customer's request; or (ii) provide the formula that
                   the utility would use to calculate the customer's
                   maximum possible stranded cost exposure without
                   mitigation, to enable the customer to assess whether to
                   become a wholesale transmission customer.  The customer
                   should specify in its request, to the extent possible,
                   the date on which the customer would become a wholesale
         Docket Nos. RM95-8-000
           and RM94-7-001              -239-
                   transmission customer of the utility and the amount of
                   generation, if any, it will continue to purchase from
                   its existing supplier.  The customer may seek further
                   information on how the stranded cost charge would vary
                   as a result of choosing different dates or different
                   amounts of substitute purchases.  The customer also
                   should indicate its preferred payment method(s) (e.g.,
                   a monthly or annual adder to its transmission rate or
                   an up-front lump-sum payment).   
              (2)  The utility shall, within thirty days of receipt of the
                   request, or other mutually agreed upon period, provide
                   to the customer:  (i) the customer's maximum possible
                   stranded cost exposure without mitigation; or (ii) the
                   formula that the utility would use to calculate the
                   customer's maximum possible stranded cost exposure
                   without mitigation.  The utility's response should
                   indicate the period over which the utility proposes to
                   charge the departing customer.  There should be
                   appropriate support for each element in the calculation
                   or formula to enable the customer to understand the
                   basis for the element.  The utility should provide a
                   detailed rationale for its proposal as to how long the
                   utility reasonably expected to keep the customer.  The
                   utility also should address how it intends to mitigate
                   stranded costs.  
         Docket Nos. RM95-8-000
           and RM94-7-001              -240-
              (3)  If the customer believes that the utility has failed to
                   establish that it had a reasonable expectation of
                   continuing to serve the customer or that the proposed
                   maximum stranded cost charge without mitigation (or
                   formula) is unreasonable, it will have thirty days in
                   which to respond to the utility explaining why it
                   disagrees with the charge.  The parties should then
                   attempt to reach a mutually-agreeable charge for
                   stranded costs within a reasonable period.  
              (4)  If the parties are unable to resolve the matter
                   pursuant to the procedures specified in (1)-(3) above,
                   the customer may either:  (a) file a complaint with the
                   Commission under section 206 of the FPA to seek a
                   Commission determination whether the utility has met
                   the reasonable expectation standard and, if so, whether
                   the proposed maximum stranded cost charge (or formula)
                   satisfies the other evidentiary standards set forth in
                   this rule; 298/ or (b) wait until the proposed
                   stranded cost charge is filed under section 205 of the
                   FPA, and contest it at that time.  In either case,
                   i.e., a section 205 or 206 proceeding, the utility
                   would only be able to seek stranded cost recovery
                   according to the formula and other terms identified in

         298/ If a complaint is filed, neither the customer nor the
              utility could raise issues not identified in their earlier
              discussions.
         Docket Nos. RM95-8-000
           and RM94-7-001              -241-
                   its earlier discussions with the customer.
                        (11) State Mechanisms to Address Stranded Costs
                             Caused By Retail Wheeling
              The initial NOPR set forth a number of mechanisms that the
         Commission believes states can use to address stranded costs
         caused by retail wheeling and retail-turned-wholesale customers.
         We suggested that a state that permits a retail franchise
         customer to become a wholesale entity may consider whether to
         impose an exit fee prior to, or as a condition of, creating the
         wholesale entity. 299/  We also suggested that a state may
         consider whether to require payment of an exit fee prior to a
         franchise customer being permitted to obtain unbundled retail
         wheeling.  We noted that, in situations in which local
         distribution facilities are used by a retail wheeling customer,
         the state may consider whether to allow recovery of stranded
         costs through rates for local distribution services.  Further, if
         a state decides not to impose an exit fee, or a surcharge through
         distribution rates, it may consider whether to allow recovery of
         stranded costs from remaining retail customers or whether
         shareholders should bear all or part of those costs.
              We further suggested the possibility that state condemnation
         proceedings will provide a forum for a utility to seek recovery
         of any stranded costs where a new wholesale entity obtains
         ownership or control of a franchise utility's transmission or

         299/ Stranded Cost NOPR at 32,878.
         Docket Nos. RM95-8-000
           and RM94-7-001              -242-
         distribution facilities.  The Commission solicited comments on
         other mechanisms that states can use to determine whether to
         allow stranded cost recovery, and from whom to allow recovery,
         and whether those mechanisms are adequate to deal with retail
         stranded costs.
                             (a)  Comments
              We note, as an initial matter, that many of the state
         commission commenters did not specifically respond to our
         questions concerning mechanisms available to the states for
         addressing stranded costs.  Those that did, such as NARUC, the
         Texas Commission and the Vermont Department, however, agree that
         the states have a variety of mechanisms available to deal with
         stranded costs.  In addition to the mechanisms that we identified
         in the initial NOPR (i.e., imposing an exit fee prior to, or as a
         condition of, creating the wholesale entity; requiring an exit
         fee before a franchise customer is permitted to obtain unbundled
         retail wheeling; imposing a surcharge on local distribution
         rates; or state condemnation proceedings), these commenters
         identified the following:  (1) avoiding stranded costs in the
         first instance by seeking to preserve the integrity of the
         utility's franchised service territory; 300/ (2) seeking to
         reduce the burden of uneconomic costs through accelerated

         300/ The Texas Commission suggests, for example, that a state
              might limit certain forms of retail competition, such as
              retail wheeling or multiple certification in utility service
              areas.
         Docket Nos. RM95-8-000
           and RM94-7-001              -243-
         depreciation, revaluing of assets, or adjusting returns during
         the transition period; (3) allowing utilities to charge
         discounted rates (i.e., below embedded cost but above marginal
         cost) or reforming retail rates through new rate methodologies
         such as performance-based pricing or price caps; (4) charging
         access fees to generating entities seeking to enter retail
         markets; (5) adopting tax-based solutions, such as credits or
         deductions; (6) requiring utility write-offs of uneconomic costs;
         (7) establishing a stranded cost recovery fund to be funded
         through a broad-based surcharge or a tax on retail market
         participants; (8) encouraging research and development of more
         efficient end-use electrical technologies; and (9) not
         guaranteeing service to a departing customer that seeks to resume
         retail service if capacity is unavailable when the customer seeks
         to return.  NARUC suggests that these options are not mutually-
         exclusive, but instead could be used in combination with others
         depending on the particular circumstances.
              In response to our question whether these mechanisms are
         adequate to deal with retail stranded costs, NARUC submits that
         the states have adequate legal authority to impose any existing
         regulatory mechanisms or to enact new mechanisms that may be
         needed to address stranded cost issues.  NARUC further states
         that whether these mechanisms are adequate to provide utilities
         firm assurance that stranded costs will be recovered is not
         relevant to the Commission's inquiry.  It argues that whether a
         Docket Nos. RM95-8-000
           and RM94-7-001              -244-
         utility in a particular case recovers all or part of what it
         identifies as stranded retail costs should be a fact-based
         determination made by the appropriate state commission(s).
                             (b)  Preliminary Findings
              We are satisfied that the states do have a number of
         mechanisms available to them to address stranded costs that
         result from retail customers who obtain retail wheeling, in order
         to reach a different generation supplier. 301/  We encourage
         the states to use the mechanisms available to them in whatever
         way they deem appropriate to address stranded costs.
                        (12) Commission Authority to Regulate Transmission
                             Rates, Terms, and Conditions for Unbundled
                             Retail Transactions and Definition of State
                             Jurisdictional Local Distribution
              In the NOPR, the Commission stated that it has exclusive
         jurisdiction over the rates, terms and conditions of unbundled
         retail interstate transmission services.  We based our conclusion
         in that regard on the plain meaning of the FPA and noted that
         there is nothing in the statute, the legislative history, or the
         case law to indicate that the Commission's jurisdiction over the
         rates, terms and conditions of transmission in interstate
         commerce extends only to wholesale transmission and not to retail
         transmission. 302/  In the initial NOPR, we left open the
         question of the jurisdictional line between Commission-

         301/ As discussed above, we have determined that we will address
              stranded costs caused by retail-turned-wholesale customers.
         302/ Stranded Cost NOPR at 32,876-77.
         Docket Nos. RM95-8-000
           and RM94-7-001              -245-
         jurisdictional "transmission" and state-jurisdictional "local
         distribution."  However, as discussed, we believe it is
         appropriate to set forth our views in this document on the
         demarcation of our respective authorities in this regard.
                             (a)  Comments
              Some commenters note that the Commission's authority to
         regulate sales for resale and transmission of electric energy in
         interstate commerce is premised on Congressional intent to fill
         the "Attleboro gap."  These commenters note that Congress enacted
         the FPA to complement, not diminish, state authority.  In light
         of this complementary jurisdictional posture, several commenters
         believe the Commission must explain how an unbundled retail sale
         is different from a bundled retail sale, which state commissions
         have regulated and will continue to regulate.
              Various non-investor-owned utility commenters, including the
         Illinois Commission and NASUCA, maintain that the Commission does
         not have jurisdiction over transmission service for an unbundled
         retail transaction.  NARUC maintains that the issue is, at the
         very least, unsettled.  Therefore, before addressing the question
         of whether and how the Commission has jurisdiction over retail
         stranded costs, these commenters argue that the Commission should
         first re-examine whether its jurisdictional premise is correct,
         or simply convenient.  Investor-owned utility commenters, on the
         other hand, generally concur with the conclusions in the NOPR
         regarding Commission jurisdiction.
         Docket Nos. RM95-8-000
           and RM94-7-001              -246-
              The Illinois Commission maintains that this Commission's
         jurisdiction extends only to the transmission of electricity
         between utility systems.  It fails to see how "unbundling" of
         generation service from transmission/distribution services, in
         order to effectuate "retail wheeling," changes the basic
         intrastate nature of such services.  The Illinois Commission
         states that if unbundled retail transmission is within the scope
         of federal jurisdiction, then one may question why the retail
         transmission portion of bundled services would not also be
         subject to Commission jurisdiction.  It maintains that there is
         no legal or policy foundation supporting Commission jurisdiction
         over either bundled or unbundled retail electric services.
              The Illinois Commission further argues that the case law
         relied upon in the NOPR fails to establish that the Commission
         has retail wheeling ratemaking authority.  The Illinois
         Commission contends that each of the cases cited by the
         Commission (as well as the FPA itself) all predate the issues of
         retail wheeling and retail stranded costs.  Thus, according to
         the Illinois Commission, the courts have never contemplated
         retail wheeling or the effects that retail wheeling would have in
         terms of stranded costs for public utilities or transmission
         carriers.  The Illinois Commission argues that, because section
         201(a) of the FPA prohibits infringement of Federal regulation on
         matters subject to regulation by the states and because states
         currently regulate bundled retail transmission, the Commission is
         Docket Nos. RM95-8-000
           and RM94-7-001              -247-
         necessarily precluded by the FPA from regulating retail
         transmission.
              The Illinois Commission notes that under the Natural Gas
         Act, the states, and not the Commission, determine the rates,
         terms, and conditions of unbundled retail transportation services
         provided by local distribution companies.  The Illinois
         Commission recommends that the Commission apply to the electric
         industry the same policy that it has adopted concerning its
         regulation of the gas industry and leave unbundled retail service
         regulation to state authorities.
              Notwithstanding the jurisdictional debate, other state
         commission commenters such as the Ohio Commission contend that
         Commission assertion of jurisdiction may chill state willingness
         to undertake competitive reform at a retail level. 303/
         These commenters further contend that Commission intervention in
         retail ratemaking will undermine a state's ability to address
         retail issues without being "second guessed."  Commenters view
         this regulatory uncertainty as an unwarranted and unnecessary

         303/ The Ohio Commission proposes a model for drawing the line of
              demarcation between federal and state jurisdiction whereby
              the states would have rate jurisdiction over the wheeling-in
              portion of unbundled retail service (i.e., the point at
              which retail power enters the system of the last entity who
              redelivers the power to the end-use customer) and this
              Commission would retain jurisdiction over the wheeling-out
              and wheeling-through portions of a transaction.  It contends
              that retention of jurisdiction over a portion of wheeling is
              necessary for states to be able to assess retail stranded
              costs.
         Docket Nos. RM95-8-000
           and RM94-7-001              -248-
         result of the Commission's purported invalid assumption of
         jurisdiction.
                             (b)  Commission Ruling
              We reaffirm our legal conclusion that the Commission has
         jurisdiction over the rates, terms and conditions of unbundled
         interstate transmission services by public utilities to retail
         customers, and that we have the authority to address retail
         stranded costs through our jurisdiction over such services.
              However, we also believe the States have authority to
         address retail stranded costs through their jurisdiction over
         facilities used in local distribution. 304/  It is therefore
         important to define what we believe to be the legal demarcation
         between "transmission in interstate commerce" and "local
         distribution," as used in the FPA.  In addition, this demarcation
         is important because of the consequences it will have for the
         public utility facilities that will be affected by the open
         access requirements being proposed.  We set forth below our
         jurisdictional analysis, and technical factors, for determining
         what constitutes "facilities used in local distribution."
                             (13) Stranded Costs in the Context of
                                  Voluntary Restructuring
              As we note in the Open Access NOPR, the functional
         unbundling of wholesale services that we are proposing does not

         304/ States also have the authority to address so-called
              "stranded benefits" (e.g., environmental benefits associated
              with conservation, load management and other DSM programs)
              through their jurisdiction over local distribution.
         Docket Nos. RM95-8-000
           and RM94-7-001              -249-
         require corporate unbundling (disposition of assets to a non-
         affiliate, or establishing a separate corporate affiliate to
         manage a utility's transmission assets) in any form.  At the same
         time, we recognize that some utilities may ultimately choose such
         a course of action.  The Commission is willing to consider case-
         specific proposals for dealing with stranded costs in the context
         of any restructuring proceedings that may be instituted by
         individual utilities.
              G.  Transmission/Local Distribution
              In light of the proposals in both the Open Access NOPR and
         the Stranded Cost Supplemental NOPR, the Commission believes it
         is important to express its views on the distinction between
         Commission-jurisdictional transmission in interstate commerce,
         and state-jurisdictional local distribution, in the context of
         unbundled wheeling by public utilities. 305/  The distinction
         is important for three reasons.  First, facilities that can be
         used for wholesale transmission in interstate commerce would be
         subject to the Commission's open access requirements.  It is
         important that public utilities and their customers have a good
         understanding of which facilities will be subject to such

         305/ The term "wheeling" is intended to cover any delivery of
              electric energy from a supplier to a purchaser, i.e.,
              transmission, distribution, and/or local distribution.
              The Commission also has jurisdiction to order wholesale
              transmission services in either interstate or intrastate
              commerce by transmitting utilities that are not also public
              utilities.  See Tex La Electric Cooperative of Texas, Inc.,
              67 FERC ¶ 61,019 (1994), reh'g pending.
         Docket Nos. RM95-8-000
           and RM94-7-001              -250-
         requirements.  Such understanding will be crucial to appropriate
         planning as we enter into the competitive regime.  It is also
         important that utilities not be able to shield themselves from
         the Commission's open access requirements by claiming that the
         facilities necessary to deliver power to a wholesale purchaser
         are non-jurisdictional "local distribution" facilities.
              Second, as discussed supra, states may, through their
         jurisdiction over facilities used in local distribution, impose a
         surcharge on local distribution that will permit recovery of
         stranded costs resulting from retail wheeling or retail-turned-
         wholesale customers.  Providing guidance on the demarcation
         between transmission and local distribution should assure States
         that they have the ability to assess stranded costs on the
         departing customers.  This should result in more realistic
         economic evaluations by retail customers contemplating leaving
         via retail wheeling and/or municipalization.
              Third, as the structure of the electric industry continues
         to change dramatically, particularly with the wide availability
         of unbundled wholesale (and perhaps retail) services to deliver
         power and the potential for various forms of voluntary corporate
         unbundling, utilities need to know which regulator has
         jurisdiction over which facilities in order to meet State and
         Federal statutory filing requirements.
              Two specific circumstances are addressed:
                   First, what facilities are jurisdictional to
                   the Commission in a situation involving the
         Docket Nos. RM95-8-000
           and RM94-7-001              -251-
                   unbundled delivery in interstate commerce by
                   a public utility of electric energy from a
                   third-party supplier to a purchaser who will
                   then re-sell the energy to an end user?  
                   Second, what facilities are jurisdictional to
                   the Commission in a situation involving the
                   unbundled delivery in interstate commerce by
                   a public utility of electric energy from a
                   third-party supplier directly to an end user?
              Based on an analysis of the relevant legislative history and
         case law under the FPA, the Commission reaches the following
         conclusions.  With respect to the first circumstance, the
         Commission concludes that a public utility's facilities used to
         deliver electric energy to a wholesale purchaser, whether labeled
         "transmission," "distribution," or "local distribution" are
         subject to the Commission's exclusive jurisdiction under sections
         205 and 206, and that a public utility's facilities used to
         deliver electric energy from the wholesale purchaser to the
         ultimate consumer are "local distribution" facilities subject to
         the rate jurisdiction of the state. 306/
              With respect to the second circumstance, the Commission
         believes that, based on the particular facts of the case, some of
         the public utility's facilities used to deliver electric energy

         306/ There are, of course, facilities that are used to provide
              delivery to both wholesale purchasers and end users.  In
              those situations, we believe that the Commission and the
              States have jurisdiction to set rates for the services that
              are within their respective jurisdictions.  That facilities
              are used to serve resale and retail customers does not,
              however, necessarily mean that the facilities are local
              distribution facilities.
         Docket Nos. RM95-8-000
           and RM94-7-001              -252-
         to an end-user may be FERC-jurisdictional transmission
         facilities, while some of the facilities used may be state-
         jurisdictional local distribution facilities.  
              We set forth below the relevant legislative history and case
         law, our legal conclusions, and the factors which we believe are
         indicative of whether facilities are used in "local distribution"
         or "transmission in interstate commerce," as those terms are used
         in the FPA.
                   1.  Relevant Federal Power Act (FPA) Provisions
              The Commission's jurisdiction is set forth in section 201 of
         the FPA. 307/  Section 201(b)(1) provides in pertinent part:
                   The provisions of this Part shall apply to
                   the transmission of electric energy in
                   interstate commerce and to the sale of
                   electric energy at wholesale in interstate
                   commerce . . . . The Commission shall have
                   jurisdiction over all facilities for such
                   transmission or sale of electric energy, but
                   shall not have jurisdiction . . . . over
                   facilities used in local distribution or only
                   for the transmission of electric energy in
                   intrastate commerce, or over facilities for
                   the transmission of electric energy consumed
                   wholly by the transmitter. [308/]
              Section 201(c) provides that:
                   electric energy shall be held to be
                   transmitted in interstate commerce if
                   transmitted from a State and consumed at any
                   point outside thereof; but only insofar as
                   such transmission takes place within the

         307/ 16 U.S.C. § 824.
         308/ 16 U.S.C. § 824(b) (emphasis added).
         Docket Nos. RM95-8-000
           and RM94-7-001              -253-
                   United States. [309/]
              Some of the court decisions that construe jurisdictional
         facilities under section 201 also construe the Commission's
         jurisdiction under section 203.  Section 203(a) provides, in
         relevant part:
                   No public utility shall sell, lease, or
                   otherwise dispose of the whole of its
                   facilities subject to the jurisdiction of the
                   Commission, . . . or by any means whatsoever,
                   directly or indirectly, merge or consolidate
                   such facilities or any part thereof with
                   those of any other person . . . without first
                   having secured an order of the Commission to
                   do so. [310/]
              In addition, section 206(d) concerns facilities "under the
         jurisdiction of the Commission":
                   The Commission upon its own motion, or upon
                   the request of any State commission whenever
                   it can do so without prejudice to the
                   efficient and proper conduct of its affairs,
                   may investigate and determine the cost of the
                   production or transmission of electric energy
                   by means of facilities under the jurisdiction
                   of the Commission in cases where the
                   Commission has no authority to establish a
                   rate governing the sale of such energy.
                   [311/]
                   2.  Legislative History of the FPA
              The relevant legislative history of the general purposes of
         Title II of the FPA, and of section 201 in particular, focuses
         primarily on bundled sales of electric energy and does not

         309/ 16 U.S.C. § 824(c).
         310/ 16 U.S.C. § 824b (emphasis added).
         311/ 16 U.S.C. § 824e(d) (emphasis added).
         Docket Nos. RM95-8-000
           and RM94-7-001              -254-
         directly address the issue of what constitutes local distribution
         as opposed to transmission in interstate commerce.      
              In discussing the general purposes of Title II of the House
         bill, the House Report states:
                   Title II . . . establishes for the first time
                   regulation of electric utility companies
                   transmitting energy in interstate commerce.
                             *         *         *
                   .  .  .  Under the decision of the Supreme Court
                   of the United States in Public Utilities
                   Commission v. Attleboro Steam & E. Co. (273 U.S.
                   83 [(1927)]) [(Attleboro)], the rates charged in
                   interstate wholesale transactions may not be
                   regulated by the States.  Part II gives the
                   Federal Power Commission jurisdiction to regulate
                   these rates.  A "wholesale" transaction is defined
                   to mean the sale of electric energy for resale and
                   the Commission is given no jurisdiction over local
                   rates even where the electric energy moves in
                   interstate commerce. [312/]
              In its analysis of section 201, the House Report states:
                   As in the Senate bill no jurisdiction is given
                   over local distribution of electric energy, and
                   the authority of States to fix local rates is not
                   disturbed even in those cases where the energy is
                   brought in from another State. [313/]
              The Senate Report's discussion of the general purposes of
         the FPA states:
                   The decision of the Supreme Court in
                   [Attleboro] placed the interstate wholesale
                   transactions of the electric utilities
                   entirely beyond the reach of the States.
                   Other features of this interstate utility
                   business are equally immune from State

         312/ H.R. Rep. No. 1318, 74th Cong., 1st Sess. 7-8 (1935).
         313/ Id. at 27.
         Docket Nos. RM95-8-000
           and RM94-7-001              -255-
                   control either legally or practically.
                   [314/]
              In discussing material differences between the final version
         of the Senate bill and the original version, the Senate Report
         states:
                   Subsection (b), formerly (a), which states
                   the subject matter to which the part relates,
                   has been clarified to make plain that it
                   includes interstate transmission where there
                   is no sale and excludes all facilities used
                   only for production of transmission in
                   intrastate commerce or in local distribution.
                   [315/]
              In discussing section 201 of the Senate bill, the Senate
         Report further states:
                   The rate-making powers of the Commission are
                   confined to those wholesale transactions
                   which the Supreme Court held in [Attleboro]
                   to be beyond the reach of the States.
                   Jurisdiction is asserted also over all
                   interstate transmission lines whether or not
                   there is sale of the energy carried by those
                   lines and over the generating facilities
                   which produce energy for interstate
                   transmission and sale.  It is obvious that no
                   steps can be taken to secure the planned
                   coordination of this industry on a regional
                   scale unless all of the facilities, other
                   than those used solely for retail
                   distribution, are made subject to the
                   jurisdiction of the Commission.  Facilities
                   used only for intrastate commerce or local
                   distribution are expressly excluded from the

         314/ S. Rep. No. 621, 74th Cong., 1st Sess. at 17 (1935).  See
              id. at 18 ("The revision [between the original and final
              versions of the Senate bill] has also removed every
              encroachment upon the authority of the States.  The revised
              bill would impose Federal regulation only over those matters
              which cannot effectively be controlled by the States.")
         315/ Id. at 19.
         Docket Nos. RM95-8-000
           and RM94-7-001              -256-
                   operation of the act. [316/]
              The Conference Report adds little description regarding
         jurisdictional facilities.  In reference to section 201(b) it
         states that:
                   [T]he language of the House amendment has
                   been followed with a clarifying phrase added
                   to remove any doubt as to the Commission's
                   jurisdiction over facilities used for the
                   generation and local distribution of electric
                   energy to the extent provided in other
                   sections of this part and the part next
                   following. [317/]
              In addition to the above statements pertaining to section
         201 of the FPA, Congress referenced distribution of energy in the
         legislative history of section 206(d).  Section 206(d) was
         originally enacted as section 206(b) of the FPA.  Under the
         Regulatory Fairness Act of 1988, 318/ section 206(b) was
         redesignated as section 206(d).
              The Conference Report on the original FPA does not address
         section 206(b).  The Senate Report on the FPA bill states in
         pertinent part:
                        Subsection (b) authorizes the Commission
                   to investigate and determine the cost of the
                   production or transmission of electric energy
                   by means of facilities under the jurisdiction
                   of the Commission in cases where the
                   Commission has no authority to establish a

         316/ Id. at 48.  The provisions of the Senate bill regarding
              federal jurisdiction over generating facilities were
              eliminated from the final version of the bill.
         317/ H.R. Conf. Rep. No. 1903, 74th Cong., 1st Sess. 74 (1935).
         318/ Pub. L. No. 100-473, 102 Stat. 2299 (1988).
         Docket Nos. RM95-8-000
           and RM94-7-001              -257-
                   rate governing the sale of such energy. . . .
                   Since the rate-making powers granted to the
                   Commission apply only to the wholesale rates
                   of energy sold in interstate commerce, this
                   last subsection should be of great benefit in
                   removing the practical difficulty which the
                   States may encounter in regulating the
                   interstate distribution rates which are left
                   under their control.  Such rate regulation
                   involves the examination and valuation of
                   property outside the State.  The task is one
                   requiring an agency with a jurisdiction
                   broader than that of a single State.  The
                   authority of the Federal Commission is to
                   render assistance to the State commissions in
                   a way which would preserve and make more
                   effective the jurisdiction which is thus left
                   to the States. [319/]
              The House Report discusses section 206(b) as follows:
                   This subsection reaches those situations
                   where electric energy is transmitted in
                   interstate commerce by the same company which
                   distributes it locally, and will greatly aid
                   State commissions in fixing reasonable rates
                   in such cases. [320/]
              Thus, the discussions in the two reports do not appear to
         contemplate a situation in which the transmitter and seller of
         electric energy are different, and neither is a "local"
         distributor.  The House Report expressly refers to the same
         company being the transmitter and seller of electric energy.  The
         Senate Report by its terms addresses the regulation of interstate

         319/ S. Rep. No. 621, 74th Cong., 1st Sess. 51 (1935) (emphasis
              added).
         320/ H.R. Rep. No. 1318, 74th Cong., 1st Sess. 29 (1935)
              (emphasis added).
         Docket Nos. RM95-8-000
           and RM94-7-001              -258-
         distribution rates. 321/  
              The above legislative history on sections 201 and 206(b)
         does not provide any definitive answers to the questions raised.
         We therefore turn to the case law under the FPA.
                   3.  Case Law under the FPA
              Jersey Central Power & Light Company v. Federal Power
         Commission (Jersey Central) 322/ was the first of the major
         FPC jurisdictional cases considered by the Supreme Court.  The
         case involved the acquisition by New Jersey Power and Light
         Company (New Jersey Power) of certain securities of Jersey
         Central Power & Light Company (Jersey Central) without the
         Commission's prior approval.  The question before the Court was
         whether Jersey Central was a "public utility" under section
         201(e) 323/ of the FPA so that the Commission's prior
         approval of the stock acquisition was necessary under section 203
         of the FPA.

         321/ The Senate Report states that interstate distribution rates
              are left in the States' control.  Obviously, the Senate drew
              a distinction between interstate distribution (left in the
              States' control) and interstate transmission (given to the
              FPC).  Compare S. Rep. No. 621 at 49 with H.R. Rep. No. 1318
              at 51.
         322/ 319 U.S. 61 (1943) (Jersey Central).
         323/ Section 201(e) defines a "public utility" as "any person who
              owns or operates facilities subject to the jurisdiction
              under this Part (other than facilities subject to such
              jurisdiction solely by reason of section 210, 211, or 212)."
              16 U.S.C. § 824(e).  The section as adopted in 1935 did not
              contain the parenthetical, which was adopted in 1978 as part
              of the Public Utility Regulatory Policies Act.
         Docket Nos. RM95-8-000
           and RM94-7-001              -259-
              Jersey Central owned transmission facilities that connected
         to facilities that Public Service Electric & Gas Company (Public
         Service) owned.  The interconnection of these transmission
         facilities was in New Jersey.  Public Service's facilities in
         turn connected to the facilities of the Staten Island Edison
         Corporation (Staten Island Edison), a New York utility, at the
         mid-channel of Kill van Kull, a body of water separating New
         Jersey and New York.  Jersey Central delivered energy to and
         received energy from Public Service under contract, and Public
         Service delivered energy to and received energy from Staten
         Island Edison under contract. 324/
              The Court found that, although Jersey Central generated and
         received electricity only in New Jersey, some of the electric
         energy that it dispatched to Public Service "was instantaneously
         transmitted to New York." 325/  The Court held that "[t]his
         evidence . . . furnishes substantial basis for the conclusion of
         the Commission that facilities of Jersey Central are utilized for
         the transmission of electric energy across state lines." 326/
         Therefore, the Court found that Jersey Central was a public
         utility within the meaning of section 201(e). 327/

         324/ Jersey Central, 319 U.S. at 63-65.
         325/ Id. at 66.
         326/ Id. at 67 (citation omitted).
         327/ Id. at 73.
         Docket Nos. RM95-8-000
           and RM94-7-001              -260-
              The Court cited Attleboro, in which the Court found that the
         sale of locally produced electric energy for use in another state
         resulted in the transmission of electric energy in interstate
         commerce, even though title passed at the state line. 328/
         In Jersey Central, the Court explained the rationale for federal
         jurisdiction as follows:
                   [Section 201(c) of the FPA] defines the
                   electric energy in commerce as that
                   "transmitted from a State and consumed at any
                   point outside thereof."  There was no change
                   in this definition in the various drafts of
                   the bill.  The definition was used to "lend
                   precision to the scope of the bill."  It is
                   impossible for us to conclude that this
                   definition means less than it says . . . .
                   The purpose of this act was primarily to
                   regulate the rates and charges of the
                   interstate energy. [329/]
              The Court in Jersey Central thus interpreted the FPA as
         placing within the federal province regulation of wholesale sales
         of electric energy that, in any manner, flows in interstate
         commerce.  The language quoted above and the citation to section
         201(c) of the FPA, to be relied upon in subsequent Supreme Court
         cases, strongly suggested that the Commission's jurisdiction was
         not based on whether there was a sale by the utility, but rather
         on the flow of electric energy either into or out of a state, so
         long as the energy crosses state lines.

         328/ 273 U.S. at 86, 89-90.
         329/ 319 U.S. at 71 (footnote omitted).
         Docket Nos. RM95-8-000
           and RM94-7-001              -261-
              Connecticut Light & Power Company v. Federal Power
         Commission (CL&P), 330/ which was decided two years after
         Jersey Central, is the leading case interpreting the section
         201(b) local distribution proviso.  In CL&P, the Commission
         sought to regulate the accounting practices of Connecticut Light
         & Power Company (CL&P). 331/  At issue was whether CL&P was a
         "public utility" under the FPA.  The utility's system encompassed
         an area solely within a single state (Connecticut) 332/ and
         did not interconnect with any other company that operated out of
         state. 333/  "Its purchases and sales, its receipts and
         deliveries of power, [were] all within the state." 334/
         However, CL&P did purchase energy from companies that had, in
         turn, purchased energy from Massachusetts.  The company also sold
         energy to a municipality that exported a portion of that energy
         to Fishers Island, located off the coast of Connecticut but
         "territory of New York." 335/  The Commission based its
         jurisdiction on these few transactions. 336/

         330/ 324 U.S. 515 (1945) (CL&P).
         331/ Id. at 517.
         332/ Id. at 518.
         333/ Id. at 521.
         334/ Id. at 522.
         335/ Id. at 519-21.
         336/ Id.
         Docket Nos. RM95-8-000
           and RM94-7-001              -262-
              The Court of Appeals affirmed the Commission, holding that
         the Commission's jurisdiction extended to "electric distribution
         systems which normally would operate as interstate businesses."
         The Court of Appeals found that:
                   whether or not the facilities by which
                   petitioner distributes energy from
                   Massachusetts should be classified as 'local'
                   is not relevant to this case.  The sole test
                   of jurisdiction of the Commission over
                   accounts is whether these facilities, 'local'
                   or otherwise, are used for the transmission
                   of electric energy from a point in one state
                   to a point in another. [337/]
                The Supreme Court reversed.  It held that the statutory
         language in section 201(b) of the FPA providing that the
         Commission "shall not have jurisdiction . . . over facilities
         used in local distribution" is a limitation upon Commission
         jurisdiction that "the Commission must observe and the courts
         must enforce." 338/  In analyzing the statute, the Court
         stated:
                   It has never been questioned that
                   technologically generation, transmission,
                   distribution and consumption are so fused and
                   interdependent that the whole enterprise is
                   within the reach of the commerce power of
                   Congress, either on the basis that it is, or
                   that it affects, interstate commerce, if at
                   any point it crosses a state line.
                             *         *         *

         337/ Id. at 522, quoting Connecticut Light & Power Co. v. FPC,
              141 F.2d 14, 18 (D.C. Cir. 1944).
         338/ 324 U.S. at 529.
         Docket Nos. RM95-8-000
           and RM94-7-001              -263-
                        But whatever reason or combination of
                   reasons led Congress to put the provision in
                   the Act, we think it meant what it said by
                   the words "but shall not have jurisdiction .
                   . . over facilities used in local
                   distribution."  Congress by these terms
                   plainly was trying to reconcile the claims of
                   federal and local authorities and to
                   apportion federal and state jurisdiction over
                   the industry. [339/]
         The Court decided that this limitation on jurisdiction was "a
         legal standard that must be given effect in this case in addition
         to the technological transmission test." 340/
              The Court stated that whether or not local distribution
         facilities carried out-of-state electric energy was irrelevant.
         Whatever the origin of the electric energy they carried, so long
         as the utility used the lines for local distribution, 341/
         they were exempt from federal jurisdiction. 342/  In fact,
         the Court stated that local distribution facilities "may carry no
         energy except extra-state energy and still be exempt under the
         Act."  Id. at 531.  The Court concluded that the Commission's
         order:
                   must stand or fall on whether this company owned
                   facilities that were used in transmission of interstate
                   power and which were not facilities used in local

         339/ Id. at 529-31.
         340/ Id. at 531.
         341/ It appears that while the Company received power (at one
              location) at 66 kV, it primarily owned facilities at 13.8 kV
              and below.
         342/ 324 U.S. at 531.  
         Docket Nos. RM95-8-000
           and RM94-7-001              -264-
                   distribution. [343/]  
              Upon reversing the Court of Appeals, the Court commented, in
         dictum, on the evidence the Commission had relied upon in finding
         that the facilities in question were used for transmission.  It
         noted that the Commission had relied upon certain gas
         transportation cases in concluding that transmission extends from
         the generator to the point where the function of conveyance in
         bulk over distance is completed and the process of subdividing
         the energy to serve ultimate consumers, which is the
         characteristic of "local distribution," is begun.  The Court
         cautioned:
                   But a holding that distributing gas at low
                   pressure to consumers is a local business is
                   not a holding that the process of reducing it
                   from high to low pressure is not also part of
                   such local business.  In so far as the
                   Commission found in these cases a rule of law
                   which excluded from the business of local
                   distribution the process of reducing energy
                   from high to low voltage in subdividing it to
                   serve ultimate consumers, the Commission has
                   misread the decisions of this Court.  No such
                   rule of law has been laid down. [344/]
         The Court also noted in its dictum, however, that once a company
         is properly found to be a "public utility" under the Act, the
         fact that a local commission may also have jurisdiction does not

         343/ Id. at 531 (emphasis added).
         344/ Id. at 534.  
         Docket Nos. RM95-8-000
           and RM94-7-001              -265-
         preclude exercise of the Commission's functions.  Id. at 533.
         345/  The Court instructed the lower court to remand the case
         to the Commission for a finding regarding whether the facilities
         in question were used in local distribution. 346/
              The CL&P case was ultimately disposed of without the
         Commission having made a finding that the facilities were used in
         local distribution.  While the Commission found that it was
         "extremely doubtful" that it could find that the facilities in
         question were not local distribution facilities, 6 FPC 104, 106
         (1947), the Commission did not articulate a definition of local
         distribution facilities.  

         345/ See United States v. Public Utilities Commission of
              California, 345 U.S. 295, 316 (1953) (Public Utilities
              Commission):
                   Certainly the concrete fact of resale of some
                   portion of the electricity transmitted from a
                   state to a point outside thereof invokes federal
                   jurisdiction at the outset, despite the fact that
                   the power thus used traveled along its interstate
                   route "commingled" with other power sold by the
                   same seller and eventually directly consumed by
                   the same purchaser-distributor.
              See also Arkansas Power & Light Co. v. FPC, 368 F.2d
              376, 383 (8th Cir. 1966) ("Where a company is in fact a
              public utility, all wholesale sales for resale in
              interstate commerce are subject to the provisions of
              sections 205 and 206 of the [FPA], regardless of the
              facilities used.").  The Eighth Circuit further noted
              that the section 201(b) exemption applies to a
              company's status as a public utility and not to the
              Commission's jurisdiction over sales in interstate
              commerce for resale.  Id., citing Public Utilities
              Commission, Colton, infra, and Wisconsin-Michigan,
              infra.
         346/ Id. at 536.
         Docket Nos. RM95-8-000
           and RM94-7-001              -266-
              In Wisconsin-Michigan Power Co. v. Federal Power Commission,
347/
         the Seventh Circuit held that a utility was a jurisdictional
         public utility where it operated two divisions in Wisconsin and
         Michigan in a coordinated manner such that electric energy from
         one state was transmitted to the other, and vice versa, "in
         appreciable amounts by the power company and by it commingled
         with energy generated in the two respective districts and then
         delivered to the [wholesale] customers. . . ." 348/  The
         court also rejected the notion that the energy changed its form
         or character when it was stepped down in voltage before it
         reached the wholesale purchasers. 349/
              The court in Wisconsin-Michigan distinguished between
         transmission and local distribution by focusing on wholesale
         sales of electric energy versus retail sales ("local rates") of
         electric energy.  It cited the House Report on the FPA, and
         characterized the legislative history as follows:
                   The legislative history, [H.R. Rep. No.
                   1318], 74th Cong., 1st Sess. pages 7, 8 and
                   27 [(1935)], discloses that the Congressional
                   Committee intended that the provisions of the
                   [FPA] should apply to the transmission of
                   electric energy in interstate commerce, i.e.,
                   the sale of energy at wholesale in interstate

         347/ 197 F.2d 472 (7th Cir. 1952), cert. denied, 345 U.S. 934
              (1953) (Wisconsin-Michigan).
         348/ Id. at 474.
         349/ Id. ("Obviously the energy thus transmitted in interstate
              commerce is not changed in form or in character except that
              the voltage is reduced to an extent consistent with
              efficient economic management and operation.").
         Docket Nos. RM95-8-000
           and RM94-7-001              -267-
                   commerce, but not to the retail sale of any
                   such energy in local distribution; that the
                   [FPA] left to the state the authority to fix
                   local rates where the energy is brought in
                   from other states, and that the rate making
                   power of the [FPC] was to be confined to
                   those wholesale transmissions which the
                   Supreme Court had held in [Attleboro] to be
                   beyond the reach of the state.  Under that
                   decision, said the committee, the rates
                   charged in interstate wholesale transactions
                   could not be regulated by the states.  It
                   defined a wholesale transaction as the sale
                   of electric energy for resale. [350/]
              The Seventh Circuit's characterization of the House Report
         seems to equate transmission of electric energy in interstate
         commerce with the sale of energy at wholesale in interstate
         commerce.  However, this interpretation is at odds with both the
         plain words of the statute as well as the language of the House
         Report, both of which refer to transmission in interstate
         commerce separately from sales for resale in interstate commerce.
351/
         In addition, the Senate Report, which the Seventh Circuit did not
         mention, clearly recognized jurisdiction over all interstate
         transmission lines, whether or not a sale of energy is carried by
         those lines. 352/

         350/ 197 F.2d at 476 (emphasis added).
         351/ See H.R. Rep. No. 1318 at 27.  ("Subsection (b) confers
              jurisdiction upon the Commission over the transmission of
              electric energy in interstate commerce and the sale of
              electric energy in wholesale in interstate commerce. . . . "
              emphasis added).
         352/ See S. Rep. No. 621 at 48 ("Jurisdiction is asserted over
              all interstate transmission lines whether or not there is a
              sale of the energy carried by those lines . . . .").
         Docket Nos. RM95-8-000
           and RM94-7-001              -268-
              The Wisconsin-Michigan court also cited analogous natural
         gas cases, stating that "[t]he question is essentially, when does
         interstate commerce transportation end and where do the local
         distribution facilities first become operative." 353/  The
         court further stated that:
                   [U]pon delivery to [the wholesaler] local
                   distribution begins when he resells.  His
                   sales and distribution at retail are clearly
                   local in character, and constitute only local
                   distribution; but at no point before delivery
                   to him has been completed, has interstate
                   transmission terminated.  In other words,
                   "facilities used in local distribution" means
                   facilities used for making resale and
                   distribution to consumers, jurisdiction over
                   which is left to the states.  It was only
                   because of this conclusion that the Supreme
                   Court said, [citation omitted], the Act
                   "cut[s] sharply and cleanly between sales for
                   resale and direct sales for consumptive
                   uses."  We think there is no ground for the
                   position that local distribution includes any
                   transmission occurring before the wholesaler
                   who resells at retail is reached. [354/]
              The Seventh Circuit concluded that the sales for resale were
         made in interstate commerce; that local distribution had not
         begun; that the interstate character of the transmission
         persisted until delivery to the wholesaler; that, up to that
         point, no local distribution facilities were in operation and
         that, therefore, the sales were subject to Commission regulation.
              In Federal Power Commission v. Southern California Edison

         353/ 197 F.2d at 477.
         354/ Id., citing FPC v. East Ohio Gas Co., 338 U.S. 464 (1950)
              (East Ohio).  
         Docket Nos. RM95-8-000
           and RM94-7-001              -269-
         Company (the Colton case), 355/ the Supreme Court held that
         the FPA provides a clear line of demarcation between
         jurisdictional transactions and non-jurisdictional transactions.
         However, this case, too, involved bundled sales of electric
         energy.  In the facts of the case, Southern California Edison
         Company (Edison) admitted that it was a public utility by virtue
         of owning two interstate transmission lines. 356/  At issue
         was whether its sales of electric energy to the City of Colton,
         California, for resale to Colton's retail customers, were
         jurisdictional.  Included in the electric energy that Edison sold
         to Colton was out-of-state electric energy from Hoover Dam.
         357/  The Commission ruled that the sale to Colton was a sale
         of electric energy at wholesale in interstate commerce subject to
         regulation under the FPA. 358/  In upholding the Commission,
         the Court held that Edison's importation of out-of-state
         electricity for resale to Colton sufficed to confer federal

         355/ 376 U.S. 205 (1964) (Colton).
         356/ The Supreme Court noted that Edison's status as a public
              utility did not decide the question of whether the FPC could
              assert jurisdiction over the rates for the Edison-Colton
              sale.  Id. at 208 n.3.
         357/ Id. at 208, 209 & n.5.  
         358/ Id. at 208.  See Arkansas Electric Cooperative Corp. v.
              Arkansas Public Service Commission, 461 U.S. 375, 380 (1983)
              ("[Colton] held, among other things, that . . . a California
              utility that received some of its power from out-of-state
              was subject to federal and not state regulation in its sales
              of electricity to a California municipality that resold the
              bulk of the power to others.").
         Docket Nos. RM95-8-000
           and RM94-7-001              -270-
         jurisdiction.
              The Court, citing an earlier Supreme Court case, 359/
         characterized Congressional intent in the FPA:
                   [W]hat Congress did was to adopt the test
                   developed in the Attleboro line which denied
                   state power to regulate a sale "at wholesale
                   to local distributing companies" and allowed
                   state regulation of a sale at "local retail
                   rates to ultimate consumers." [360/]
              The Court rejected the argument that FPC jurisdiction was
         confined to those interstate wholesale sales constitutionally
         beyond the power of state regulation by force of the Commerce
         Clause, and was to be determined on a case-by-case analysis of
         the impact of state regulation upon the national interest.  The
         Court stated that in the FPA:
                   [C]ongress meant to draw a bright-line easily
                   ascertained, between state and federal
                   jurisdiction, making unnecessary such case-
                   by-case analysis.  This was done in the Power
                   Act by making FPC jurisdiction plenary and
                   extend[ed] it to all wholesale sales in
                   interstate commerce except those which
                   Congress has made explicitly subject to
                   regulation by the States. [361/]
         The Court held that "[t]here is no such exception covering the
         Edison-Colton sale." 362/

         359/ Illinois Natural Gas Co. v. Central Illinois Public Service
              Co., 314 U.S. 498, 504 (1942).
         360/ 376 U.S. at 214.
         361/ Id. at 215-216.
         362/ Id. at 216 (footnote omitted).
         Docket Nos. RM95-8-000
           and RM94-7-001              -271-
              Parties in the Colton case had raised the question of
         whether jurisdiction over the Colton sale was prevented by the
         "local distribution" proviso of section 201(b).  The Court stated
         that whether facilities are local distribution facilities is a
         matter for the Commission to decide in the first instance.
         Citing CL&P, supra, it stated:
                   Whether facilities are used in local
                   distribution -- although a limitation on FPC
                   jurisdiction and a legal standard that must
                   be given effect in addition to the
                   technological transmission test ... --
                   involves a question of fact to be decided by
                   the FPC as an original matter. [363/]
         The Court cited evidentiary support and the Commission's
         expertise in such matters in upholding the Commission's
         determination that certain facilities owned by Edison were used
         exclusively to effect the wholesale sale to Colton and not for
         local distribution.  Such facilities included 12 kV lines that
         served an industrial customer, several lighted highway signs, a
         residence and a railroad section house before they reached the
         transformers in the Colton substation.  The FPC had held that
         those uses prior to the lines reaching the Colton substation did
         not transform the lines into local distribution facilities.
         364/

         363/ Id. at 210 n.6 (citation omitted).
         364/ Id. at 210 n.6.
         Docket Nos. RM95-8-000
           and RM94-7-001              -272-
              In Duke Power Company v. Federal Power Commission (Duke),
         365/ the D.C. Circuit held that a public utility's
         acquisition of facilities used solely in local distribution, and
         which would continue to be used for local distribution, was
         beyond the Commission's jurisdiction under section 203.  The case
         involved Duke Power Company's (Duke's) proposed acquisition of
         facilities owned by Clemson University (Clemson), which were used
         to distribute electricity off-campus to customers (primarily
         university personnel) in two South Carolina counties.  Clemson
         purchased the power at wholesale from Duke.  No one appeared to
         contest the conclusion that the 7 miles of distribution line and
         418 service connections owned by Clemson were "local
         distribution" facilities. 366/  Rather, the case turned on
         interpreting section 203 and whether it was intended to affect
         only acquisitions of jurisdictional facilities, or also to affect
         acquisitions of non-jurisdictional facilities.  In interpreting
         section 203, however, the D.C. Circuit extensively analyzed and
         discussed the fundamental jurisdictional lines that Congress drew
         in section 201.  
              Citing to the CL&P case, the court in Duke stated:
                   The Act, as we have seen, effectuated federal

         365/ 401 F.2d 930 (D.C. Cir. 1968) (Duke).
         366/ Duke delivered power to Clemson at a distribution voltage of
              4,160 volts.  The step-down transformers by which the
              voltage was reduced, and the substations at which the
              delivery was effected, were owned by Duke.  401 F.2d at 931,
              n.8.
         Docket Nos. RM95-8-000
           and RM94-7-001              -273-
                   control over the transmission and the sale at
                   wholesale of electric energy in interstate
                   commerce, and established the Commission's
                   regulatory power over public utilities
                   engaging in either of these pursuits.
                   [367/]  
         However, quoting CL&P, the court further stated:
                   The expression "facilities used in local
                   distribution" is one of relative generality.
                   But as used in this Act it is not a
                   meaningless generality in the light of our
                   history and the structure of our government.
                   We hold the phrase to be a limitation on
                   jurisdiction and a legal standard that must
                   be given effect in this case in addition to
                   the technological transmission test.
                   [368/]
              The court further rejected the Commission's concept that, in
         order to determine whether jurisdiction over any particular
         acquisition existed, the impact of local supervision be measured
         on a case-by-case basis.  Quoting from Colton, the court stated:
                   [T]his "flexible approach" - involving as it
                   does the consideration, inter alia, of "the
                   effect of the regulation upon the national
                   interest in the commerce" - has been flatly
                   rejected as a technique for resolving
                   jurisdictional conflicts between the
                   Commission and state bodies. . . .  We think
                   that like the line "[i]t cut sharply and
                   cleanly between sales for resale and direct
                   sales for consumptive uses" to facilitate
                   jurisdictional determinations in rate
                   regulation, "Congress meant to draw a bright
                   line easily ascertained, between state and
                   federal jurisdiction, making unnecessary such
                   case-by-case analysis," in distributing
                   regulatory power over the acquisition of

         367/ 401 F.2d at 938-39 (emphasis added, footnotes omitted).
         368/ Id. (footnote omitted).
         Docket Nos. RM95-8-000
           and RM94-7-001              -274-
                   facilities. [369/]
         The court rejected the Commission's argument that jurisdiction
         over the merger or consolidation of jurisdictional facilities
         with those of any other "person" under section 203 gave the
         Commission jurisdiction over Duke's acquisition.  The court
         stated that the FPA reflects a policy "'that matters largely of a
         local nature, even though interstate in character, should be
         handled locally and should receive the consideration of local
         [officials] familiar with the local conditions in the communities
         involved.'" 370/  
              Federal Power Commission v. Florida Power & Light Company
         371/ is the last major court case to address the Commission's
         transmission jurisdiction.  In this case, the Commission sought
         to impose its accounting rules upon Florida Power & Light Company
         (Florida Power & Light).  The company's system lay solely within
         the borders of Florida and did not directly connect with any out-
         of-state utility. 372/  The Commission held that Florida
         Power & Light did own facilities that transmitted electric energy
         in interstate commerce, but the Court of Appeals for the Fifth

         369/ Id. at 949 (footnotes omitted).
         370/ Id. at 936 (quoting from Hearings on H.R. 5423 before the
              House Committee on Interstate and Foreign Commerce, 74th
              Cong., 1st Sess. 393 (1935) (testimony of then-FPC
              Commissioner Seavey)).
         371/ 404 U.S. 453, reh'g denied, 405 U.S. 948 (1972) (Florida
              Power & Light).
         372/ 404 U.S. at 456.
         Docket Nos. RM95-8-000
           and RM94-7-001              -275-
         Circuit ruled that the Commission did not have substantial
         evidence to support its finding.
              The Supreme Court reversed.  The Supreme Court noted that
         Florida Power & Light was a member of the Florida Power Pool
         along with Florida Power Corporation (Florida Power Corp.).
         373/  In turn, Florida Power Corp. connected with Georgia
         Power Company (Georgia Power) at a "bus" 374/ south of the
         Georgia-Florida border. 375/  Florida Power Corp. regularly
         exchanged power with Georgia Power. 376/  In many instances,
         Florida Power Corp. transferred power to Florida Power & Light
         instantly after receiving power from Georgia Power, and
         transferred power to Georgia Power immediately after receiving
         power from Florida Power & Light. 377/  The Supreme Court
         found that power commingled in the bus moved across state lines,
         and concluded that Florida Power & Light engaged in transmission
         in interstate commerce.  The Court held that, to establish
         jurisdiction, the Commission need only show that "some [Florida
         Power & Light] power goes out of State." 378/  The Court

         373/ Id. at 456.
         374/ A "bus" is a connector or group of connectors that serves as
              a common connection for two or more circuits.
         375/ 404 U.S. at 457.
         376/ Id.
         377/ Id. at 457 & n.8.
         378/ Id. at 461. (emphasis omitted).
         Docket Nos. RM95-8-000
           and RM94-7-001              -276-
         further explained that "[i]f any [Florida Power & Light] power
         has reached Georgia, or [if Florida Power & Light] makes use of
         any Georgia power . . . FPC jurisdiction will attach . . . ."
         379/
              There is also a line of cases that address, among other
         things, what constitutes a Commission jurisdictional "sale of
         electric energy at wholesale" 380/ under section 201 of the
         FPA. 381/  These cases all concerned bundled sales.  While
         the issues posed above involve unbundled wheeling, the "resale"
         cases are helpful to the extent they suggest that local
         distribution takes place only after power is subdivided.  See,
         e.g., 345 U.S. at 316 ("the facilities supplied 'local
         distribution' only after the current was subdivided for
         individual consumers.").
                   4.  Natural Gas Act
              The Natural Gas Act (NGA) was adopted in 1938.  Like the
         FPA, the NGA contains language limiting the Commission's
         jurisdiction in situations involving local distribution. 382/

         379/ Id. at 461 n.10. (emphasis added).  
         380/ See Section 201(d), 16 U.S.C. § 824(d) (1988).
         381/ Public Utilities Commission, supra note 345; City of
              Oakland, California v. FERC, 754 F.2d 1378 (9th Cir. 1985)
              (Oakland).  See also Alexander v. FERC, 609 F.2d 543 (D.C.
              Cir. 1979) (Alexander).
         382/ Courts often rely on cases construing the NGA when
              interpreting the FPA, and vice versa.  E.g., Arkansas
              Louisiana Gas Co. v. Hall, 453 U.S. 571, 577 n.7 (1981).
         Docket Nos. RM95-8-000
           and RM94-7-001              -277-
              Section 1(b) of the NGA provides:
                   The provisions of this Act shall apply to the
                   transportation of natural gas in interstate
                   commerce, to the sale in interstate commerce
                   of natural gas for resale for ultimate public
                   consumption for domestic, commercial,
                   industrial, or any other use, and to natural
                   gas companies engaged in such transportation
                   or sale, but shall not apply to any other
                   transportation or sale of natural gas or to
                   the local distribution of natural gas or to
                   the facilities used for such distribution or
                   to the production or gathering of natural.
                   383/  
              There is similarity in many respects between the House and
         Senate Reports on the FPA and the NGA with respect to the
         jurisdiction given the Commission.  For example, all four reports
         mention Attleboro as placing interstate wholesale transactions
         beyond the reach of the States.  As indicated in the House Report
         on the NGA, the States could "regulate sales to consumers even
         though such sales are in interstate commerce, such sales being
         considered local in character and in the absence of congressional
         prohibition subject to State regulation."  (See H.R. Rep. No.
         709, 75th Cong., 1st Sess. 1).  However, the House and Senate
         Reports on the NGA contain identical language not found in the
         reports on the FPA:
                   In view of the importance of section 1(b), which
                   states the scope of the act, it seems advisable to
                   comment on certain provisions appearing therein.
                   It will be noted that this subsection of the bill,
                   after affirmatively stating the matters to which
                   the act is to apply, contains a provision
                   specifying what the act is not to apply to, as

         383/ 15 U.S.C. § 717(b) (emphasis added).
         Docket Nos. RM95-8-000
           and RM94-7-001              -278-
                   follows:  
                        but shall not apply to any other
                        transportation or sale of natural
                        gas or to the local distribution of
                        natural gas or to the facilities
                        used for such distribution or to
                        the production or gathering of
                        natural gas.
                   The quoted words are not actually necessary,
                   as the matters specified therein could not be
                   said fairly to be covered by the language
                   affirmatively stating the jurisdiction of the
                   Commission, but similar language was in
                   previous bills, and, rather than invite the
                   contention, however unfounded, that the
                   elimination of the negative language would
                   broaden the scope of the act, the committee
                   has included it in this bill.  That part of
                   the negative declaration stating that the act
                   shall not apply to "the local distribution of
                   natural gas" is surplusage by reason of the
                   fact that distribution is made only to
                   consumers in connection with sales, and since
                   no jurisdiction is given to the Commission to
                   regulate sales to consumers the Commission
                   would have no authority over distribution,
                   whether or not local in character.  (Emphasis
                   added). [384/]
              As a result of this language it can be argued that Congress
         considered distribution (and local distribution) only in the
         context of bundled retail sales of natural gas.  In fact, it
         appears that all of the court cases affirming the states' right
         to regulate local distribution of gas have involved bundled
         retail sales.  See Panhandle Eastern Pipe Line Co. v. Michigan
         Public Service Commission, 341 U.S. 329 (1951) (Panhandle).  
         There the Court, in affirming the State of Michigan's right to

         384/ H.R. Rep. No. 709, 75th Cong., 1st Sess. 3 (1937); S. Rep.
              No. 1162, 75th Cong., 1st Sess. 3 (1937).
         Docket Nos. RM95-8-000
           and RM94-7-001              -279-
         regulate an interstate pipeline's proposed bundled retail sales
         of gas to industrial consumers, noted that the pipeline company
         proposed to lay pipeline in "the streets and alleys of Detroit"
         and ignored the local distribution company's request for
         additional gas to meet the increased needs of the industrial
         consumers.  Id. at 333.  While the Court based its holding on a
         state's authority to regulate direct (retail) sales to an end-
         user, rather than on the basis of the section 1(b) local
         distribution provision, it also found that the proposed sales
         were "primarily of local interest" and "emphasized the need for
         local regulation."  Id.  Two years before Panhandle, the Supreme
         Court issued its decision in FPC v. East Ohio Gas Co., 338 U.S.
         465 (1949) (East Ohio).  East Ohio Gas Company owned and operated
         a natural gas business wholly within the State of Ohio.  The
         company sold gas only to Ohio customers but most of the gas was
         transported to Ohio from other states by interstate pipelines.
         These interstate pipelines connected inside Ohio with East Ohio's
         large high pressure lines.  The gas then was transported over 100
         miles through East Ohio's system to its local distribution
         system.  East Ohio argued that it was exempt from Commission
         jurisdiction because all of its facilities were local
         distribution.
              The Court disagreed, finding the Commission's jurisdiction
         extends over the transportation of gas in interstate commerce
         through high-pressure transmission lines and that distribution
         Docket Nos. RM95-8-000
           and RM94-7-001              -280-
         did not begin until the point where pressure is reduced and gas
         enters local mains.  The Court stated that:  "[w]hat Congress
         must have meant by 'facilities' for 'local distribution' was
         equipment for distributing gas among customers within a
         particular local community, not the high-pressure pipelines
         transporting the gas to the local mains." 385/
              The Commission relied in part on East Ohio's high
         pressure/low pressure distinction in a recent NGA section 7
         certificate case which authorized construction of facilities to
         bypass the local distribution company. 386/  On appeal,  the
         California Commission argued that under section 1(b) it should at
         least have "jurisdiction over the 'taps, meters and other tie-in
         facilities' that link the pipeline to end users." 387/  The
         court disagreed:
                   While as a matter of ordinary English 'local
                   distribution' might be understood to
                   encompass any delivery to an end user, that
                   is hardly the only or even more plausible
                   reading.  Distribution conjures up receiving
                   a large quantity of some good and parcelling
                   it out among many takers. [388/]

         385/ 338 U.S. at 469-70.    
         386/ See Mojave Pipeline Company, 35 FERC ¶ 61,199 (1986),
              reh'g denied, 41 FERC ¶ 61,040 (1987), reh'g denied, 42
              FERC ¶ 61,351 (1988); see also Mojave Pipeline Company,
              66 FERC ¶ 61,194 (1994), reh'g pending.
         387/ See Public Utilities Commission of the State of California
              v. FERC, et al., 900 F.2d 269, 273 (D.C. Cir. 1990)
              (footnote omitted) (WyCal).
         388/ Id. at 276.
         Docket Nos. RM95-8-000
           and RM94-7-001              -281-
              After reviewing the report language discussed above, the
         court also stated:
                   Insofar as congressional committees spoke to
                   the matter . . . they appear to have viewed
                   distribution as confined to its parcelling
                   out function and (probably) even more
                   narrowly, to parcelling out accompanied by
                   retail sales. [389/
              In Cascade Natural Gas Corporation v. FERC, et al.
         (Cascade), the court affirmed the Commission's authorizing an
         interstate pipeline under section 7 of the NGA "to construct a
         tap and meter facility that would allow it to deliver natural gas
         directly to two industrial consumers . . . ." 390/  To reach
         the interstate pipeline, the industrials constructed a nine-mile
         pipeline.  Together, the facilities bypassed the local
         distribution company. 391/
              The court rejected arguments that section 1(b) deprived the
         Commission of jurisdiction holding that:
                   "Local distribution," as Congress viewed the
                   term, involves two components:  the retail
                   sale of natural gas and its local delivery,
                   normally through a network of branch lines
                   designed to supply local consumers.
                   [392/]

         389/ Id. (emphasis in original).
         390/ 955 F.2d 1412, 1414 (10th Cir. 1992).
         391/ Unlike the situation in WyCal where the pipeline made
              direct sales to end users, in Cascade the pipeline
              transported gas purchased from third parties.  See
              Northwest Pipeline Corporation, 51 FERC ¶ 61,289 at
              61,909 (1990).
         392/ Cascade, 955 F.2d at 1421.
         Docket Nos. RM95-8-000
           and RM94-7-001              -282-
                   5.  Analysis
                   a.   What facilities are jurisdictional to the
                        Commission in a situation involving the unbundled
                        delivery in interstate commerce by a public
                        utility of electric energy from a third-party
                        supplier to a purchaser who will then re-sell the
                        energy to an end user?
              The case law supports the conclusion that any facilities of
         a public utility used to deliver electric energy in interstate
         commerce to a wholesale purchaser, whether such facilities are
         labeled "transmission," "distribution" or "local distribution,"
         are subject to the Commission's jurisdiction under sections 205
         and 206.
              This conclusion is supported by Public Utilities Commission,
         supra, in which the Supreme Court, in the section of its opinion
         addressing the section 201(b) local distribution provision, held
         that local distribution facilities began "only after the current
         was subdivided for individual consumers." 393/  Wisconsin-
         Michigan, supra, in which the Seventh Circuit held that there is
         no local distribution until the wholesaler who re-sells at retail
         is reached, is to like effect.
              This conclusion, which results in a "functional" line being
         drawn to determine Commission jurisdiction, is not only
         consistent with the case law under section 201, but is also
         consistent with our interpretation of the line drawn under newly
         amended FPA sections 211 and 212.  As long as electric energy is

         393/ 345 U.S. at 316 (footnote omitted).
         Docket Nos. RM95-8-000
           and RM94-7-001              -283-
         being sold to a legitimate wholesale purchaser, we believe the
         Commission has jurisdiction under sections 201, 205, and 206 of
         the FPA over the public utility's facilities used to deliver
         electric energy to that purchaser.
                   b.   What facilities are jurisdictional to the
                        Commission in a situation involving the unbundled
                        delivery in interstate commerce by a public
                        utility of electric energy from a third-party
                        supplier directly to an end user?
              In analyzing jurisdiction over unbundled retail wheeling, we
         believe it is important to distinguish between unbundled wheeling
         provided by the public utility who previously provided bundled
         retail service to the end user, and unbundled wheeling provided
         by other public utilities to the end user.  For example, a former
         bundled retail customer may need unbundled wheeling services from
         its previous public utility generation supplier, as well as
         unbundled wheeling from one or more intervening public utilities,
         in order to reach a distant generation supplier.  In this
         scenario, the Commission believes it would have jurisdiction over
         all of the facilities used for the unbundled wheeling provided by
         the intervening public utilities. 394/  The more difficult
         issue is whether some portion of the facilities used to transmit
         energy from the transmitting utility in closest proximity to the
         end user (the former supplier of the bundled product) is local
         distribution facilities.  We believe that in most, if not all

         394/ The Commission would not have jurisdiction over the rates
              for the sale of generation by the distant supplier because
              the transaction would be a retail sale of electric energy.
         Docket Nos. RM95-8-000
           and RM94-7-001              -284-
         circumstances, some portion will be local distribution
         facilities.
              The case law is replete with statements that the local
         distribution provision of section 201 must be given effect.
         However, the Supreme Court in both CL&P and Colton, supra, has
         stated that whether facilities are used in local distribution is
         a question of fact to be decided by the Commission as an original
         matter.  Thus, there is no clear case law on a "bright line"
         between transmission and local distribution.  In addition,
         regardless of the details of the chain of delivery services
         necessary to move electric energy from the generator to the end
         user, in most cases the last public utility in the chain will use
         facilities that historically were considered local distribution
         facilities.  Accordingly, unlike the situation involving
         unbundled wholesale wheeling, for which the case law clearly
         supports a "functional" test, the Commission believes the case
         law and practical realities of a changing industry support an
         analysis of local distribution facilities based on the
         facilities' functional as well as technical characteristics.  
              While it would be preferable to draw an absolutely "bright"
         line (e.g., based on technical characteristics such as voltage),
         this does not appear to be required by the case law and,
         importantly, would not be a workable approach in all cases
         because of the variety of circumstances that may arise and
         because utilities themselves classify facilities differently
         Docket Nos. RM95-8-000
           and RM94-7-001              -285-
         (e.g., one utility may classify a 69 kV facility as transmission;
         another may classify it as distribution).  
              There are several indicators that we propose to evaluate in
         determining whether particular facilities are transmission or
         local distribution in the case of vertically integrated
         transmission and distribution utilities. 395/
              °    Local distribution facilities are normally in close
                   proximity to retail customers.
              °    Local distribution facilities are primarily radial in
                   character.
              °    Power flows into local distribution systems, it rarely,
                   if ever, flows out.
              °    When power enters a local distribution system, it is
                   not reconsigned or transported on to some other market.
              °    Power entering a local distribution system is consumed
                   in a comparatively restricted geographical area.
              °    Meters are based at the transmission/local distribution
                   interface to measure flows into the local distribution
                   system.
              °    Local distribution systems will be of reduced voltage.
                   396/

         395/ In the case of a distribution-only utility, which is
              franchised by a State or local government and sells only at
              retail, all of the circuits (and related wires,
              transformers, towers, and rights of way) which it owns or
              operates (regardless of voltage) would be local distribution
              facilities.
         396/ The Commission has analyzed utilities' filings required by
              the Commission's regulations.  These filings are made on
              FERC Form No. 1.  While there is no uniform breakpoint
              between transmission and distribution, it appears that
              utilities account for facilities operated at greater than 30
              kV as transmission and that distribution facilities are
              usually less than 40 kV.
         Docket Nos. RM95-8-000
           and RM94-7-001              -286-
         In summary, for unbundled wholesale wheeling we will apply a
         functional test.  The only definitive question will be whether
         the entity to whom the power is delivered is a lawful wholesaler.
              For unbundled retail wheeling we will apply a combination
         functional-technical test that will take into account technical
         characteristics of the facilities used for the wheeling.  In
         most, if not all, circumstances in this situation, we expect
         there to be local distribution facilities.  To assist states in
         dealing with stranded costs resulting from retail wheeling, we
         will make every attempt to expedite a decision if a state
         requests clarification concerning whether certain facilities are
         local distribution facilities.
              By clarifying the tests the Commission will apply to
         determine if facilities used to deliver unbundled electric energy
         are FERC-jurisdictional or state-jurisdictional, we believe we
         have facilitated the ability of this Commission and, importantly,
         state commissions to assess legitimate stranded costs to
         customers who leave their existing suppliers' systems.  The
         application of these tests means that states will be able to
         address stranded costs by imposing an exit fee on departing
         retail customers, or including an adder in the retail customers'
         local distribution rates.
              H.  Implementation
              Because the proposed requirements in the Open Access NOPR
         are aimed at eliminating undue discrimination in the provision of
         Docket Nos. RM95-8-000
           and RM94-7-001              -287-
         transmission services in interstate commerce, and at achieving
         competitive bulk power markets for the benefit of electricity
         consumers, our preliminary view is that open access tariffs
         should be in place as soon as possible.  Very simply, we would
         not want to delay a program which we expect to produce
         significant ratepayer benefits over time.  We also would want to
         provide procedures and guidance for stranded cost recovery as
         soon as possible in order to complete the transition from a
         tightly-controlled cost-of-service regulatory regime to the
         competitive regime we expect in the very near future.  
              To those ends, we propose implementation procedures that the
         Commission currently believes will be appropriate for non-
         discriminatory open access transmission and stranded (transition)
         cost recovery.  These proposed implementation procedures attempt
         to balance the goals of:  placing good open access tariffs into
         effect as soon as possible; supporting the transmission pricing
         flexibility permitted by our Transmission Pricing Policy
         Statement; and providing for implementation that is
         administratively feasible for utilities, customers, and the
         Commission.
              With respect to open access, we currently estimate that
         about 137 public utilities would be required to have on file non-
         discriminatory open access tariffs if the Commission adopts a
         final rule.  
              If the Commission were to employ traditional filing
         Docket Nos. RM95-8-000
           and RM94-7-001              -288-
         procedures in implementing an open access regime, we could
         attempt to streamline the process by, for example, relying, where
         appropriate, on paper hearing procedures and technical
         conferences and summarily disposing of the maximum number of
         issues possible.  Nevertheless, we would still expect delays (and
         attendant uncertainty) measured in years. 397/  As a result,
         we propose a two-stage procedure to put in place without delay
         basic open access tariffs.  We believe this procedure will ensure
         non-discriminatory open access transmission services that would:
         (1) satisfy most utilities and customers; and (2) provide a
         framework for utilities to subsequently submit novel proposals
         that they believe to be better tailored to their individual
         circumstances.  We request comments on all aspects of the
         proposed procedure, including the proposed generic tariffs
         discussed infra.
                   1.  Two-Stage Implementation Process
                   Stage One
              The Commission proposes to put into effect (not subject to
         refund) for every public utility that owns and/or controls
         transmission facilities, pursuant to section 206 of the FPA,
         generic tariffs providing network transmission services, firm and

         397/ Such uncertainty could adversely impact on utilities'
              cost of capital.  Moreover, case-by-case implementation
              would result in a patchwork of open access around the
              country until the process is complete.  This patchwork
              of conflicting requirements could inhibit the timely
              transition to competitive markets -- a result directly
              at odds with the objectives of this proceeding.
         Docket Nos. RM95-8-000
           and RM94-7-001              -289-
         non-firm point-to-point transmission services, and ancillary
         services necessary to effect network and point-to-point service.
         398/  The Commission proposes to specify the rates, terms,
         and conditions in the final rule and to put all such tariffs into
         effect simultaneously on a date certain -- 12:00 midnight 60 days
         after the effective date of the final rule.  
              The proposed network and point-to-point tariffs contained in
         Appendices B and C establish the minimum terms and conditions
         which we believe are necessary to eliminate undue discrimination
         in the transmission of electric energy in interstate commerce.
         We propose to place these terms and conditions into effect for
         each affected public utility.  
              Although the proposed generic tariffs contain the minimum
         terms and conditions of service that is not unduly
         discriminatory, they do not contain specific rates.  However,
         section 206(a) of the FPA requires the Commission to fix by order
         the just and reasonable rate. 399/  We therefore propose to
         establish and set forth in the final rule, for each affected
         public utility, just and reasonable rates for network service,
         point-to-point service, and six identified ancillary services.
         We propose to establish such rates using the most current Form

         398/ As noted infra, we will address in a separate document
              the application of the proposed rule to public
              utilities who have open access proceedings pending
              before the Commission.
         399/ Electrical District No. 1, et al. v. FERC, 774 F.2d 490
              (D.C. Cir. 1985).
         Docket Nos. RM95-8-000
           and RM94-7-001              -290-
         No. 1 data available for each public utility, and to incorporate
         them into the generic tariffs for each affected public utility.  
              While the rates we will calculate using Form No. 1 data will
         be postage stamp rates, we wish to emphasize that utilities are
         free in Stage Two to propose immediately and support non-
         traditional conforming, as well as non-conforming, transmission
         pricing proposals consistent with the Commission's Transmission
         Pricing Policy Statement.  The proposed calculation of these
         rates is discussed in detail infra.
              Customers will be able to rely on existing contracts for
         transmission service until such contracts expire or are otherwise
         terminated.  While customers will be able to use the generic
         tariffs and any revised tariffs established in Stage Two for new
         or additional services, we do not propose to allow customers to
         seek termination of their existing transmission arrangements in
         order to use the generic or subsequently revised tariffs, unless
         such filings are contractually authorized or shown to be in the
         public interest.  Of course, to the extent that such filings are
         contractually authorized, the Commission must still determine
         whether the termination of such existing transmission
         arrangements is just and reasonable, based upon the circumstances
         presented.
              The above procedures would apply to individual public
         utility open access tariffs.  However, many public utilities
         transact under jurisdictional power pooling agreements.  As
         Docket Nos. RM95-8-000
           and RM94-7-001              -291-
         discussed herein, power pools would have to comply with the non-
         discrimination requirements of the Open Access NOPR by making
         power pool transmission services available to all wholesale
         transmission customers and offering services at rates, terms, and
         conditions that are not unduly discriminatory.  However, power
         pools raise complex issues and the Commission cannot at this time
         develop compliance tariffs for power pools.  Therefore, we seek
         comments on how to implement the NOPR for power pools.  After we
         have received comments on this matter, and before a final rule is
         adopted, we intend to hold technical conferences with power pools
         to discuss implementation issues.  After holding these technical
         conferences, and taking into account the comments received in the
         Open Access NOPR proceeding as well as in our pending Notice of
         Inquiry on Alternative Power Pooling Institutions, we will issue
         a supplemental order directing compliance for power pools.  
                   Stage Two
              The Commission proposes that Stage Two begin 61 days after
         the date the final rule becomes effective.  On and after that
         date, public utilities may propose changes to the rates, terms,
         and conditions in the generic tariffs pursuant to section 205 of
         the FPA and Part 35 of the regulations.  In addition, customers
         and others may file complaints pursuant to section 206 of the FPA
         seeking changes in the rates, terms, and conditions in the
         generic tariffs.  We note, however, that Stage Two tariffs must
         contain at least the non-price tariff terms and conditions
         Docket Nos. RM95-8-000
           and RM94-7-001              -292-
         contained in the pro forma tariffs.  Moreover, customers (or
         potential customers) dissatisfied with the generic tariffs may
         file section 211 applications at any time (i.e., before Stage
         Two).
              We are hopeful that the generic tariffs will initially be
         acceptable to large numbers of utilities and their customers.  
         Because we expect our Stage One tariffs to be satisfactory for
         the immediate needs of many transmission providers and customers,
         we would expect Stage Two proposals to be staggered somewhat,
         permitting us to process and reach final decisions more quickly
         on subsequent proposals to revise the generic tariffs.
              We propose to require any utility seeking to modify the
         generic tariffs in Stage Two to file, in addition to the other
         requirements specified in the regulations, an original and 14
         copies of the revised tariffs showing any changes proposed by
         means of highlighting and striking out.  In addition, we propose
         that the utilities also file two copies of such changes on
         diskette in ASCII format.  
                   2.  Calculations of Stage One Rates
              Because most utilities currently use embedded cost pricing
         for the transmission component of their own power sales and
         purchases, and because the Commission's Transmission Pricing
         Policy Statement requires comparability between transmission
         rates and the transmission pricing component of those power sales
         and purchases, the Commission proposes to establish rates for the
         Docket Nos. RM95-8-000
           and RM94-7-001              -293-
         generic tariffs based on embedded cost principles.  However,
         these tariffs will include a provision that allows the
         transmission provider to file unilateral changes in all rates,
         terms, and conditions any time after the effective date of the
         generic tariffs (Stage Two filings).  However, as we noted above,
         the minimally acceptable tariff terms and conditions in Stage Two
         will be the terms and conditions established in Stage One.  
              We emphasize that utilities and customers have discretion
         under the Commission's Transmission Pricing Policy Statement to
         pursue other types of rate treatments, and that they may file a
         proposal any time after the generic tariffs become effective.
         For example, Stage Two filings could include:  
              °    A filing by the public utility under section 205
                   amending the generic tariff in a limited respect, such
                   as a change in the loss factor, a change in the
                   embedded cost unit charge, implementing an option to
                   charge an incremental cost rate, including opportunity
                   cost, when capacity is constrained, or the addition of
                   another ancillary service.
              °    A filing by the public utility under section 205
                   proposing an entirely new rate method such as a zone or
                   distance based transmission rate.  The generic tariff
                   would constitute a conforming open access transmission
                   tariff, but revised tariff filings could also include
                   nonconforming proposals.
         Docket Nos. RM95-8-000
           and RM94-7-001              -294-
              °    A complaint by a customer (or potential customer) under
                   section 206 seeking limited changes to the generic
                   tariff, such as a change in the loss factor, a change
                   in the embedded cost unit charge, or the addition of
                   another ancillary service.
              °    A complaint by a customer (or potential
                   customer) under section 206 proposing an
                   entirely new rate method.
              We expect that, for many transmission providers and
         customers, the Stage One tariffs will satisfy their immediate
         needs.  For example, a customer might believe that it could
         demonstrate in a section 206 proceeding that a lower rate is
         appropriate, but decide the monetary impact is not sufficient to
         justify the filing of a complaint because its current needs are
         small or because the expected rate reduction is slight.  In this
         situation, the customer may delay raising objections to the Stage
         One tariffs until the company files its next general rate case.
         Also, a company might believe that it could demonstrate that a
         higher rate is reasonable, but decide that its resources are best
         spent comprehensively designing a Stage Two non-traditional
         tariff, such as, a distance sensitive rate, a non-conforming
         proposal, or a spin-off of transmission assets into a separate
         company.  Similarly, companies negotiating regional transmission
         tariffs may decide to devote their resources to that project
         rather than fine tuning their company specific rates.  
         Docket Nos. RM95-8-000
           and RM94-7-001              -295-
              If we had not proposed this two-stage process and simply
         directed the filing of company specific tariffs, utilities and
         customers would have been forced to proceed on an inflexible
         schedule.  In addition, parties may have felt pressured to file
         proposals prematurely out of concern that a failure to do so
         would prejudice their ability to initiate them later.  We believe
         that industry participants are better served by a process that,
         in addition to avoiding the delay inherent in a series of
         separate section 206 compliance filings, allows affected parties
         to raise these complex issues when it best meets their needs and
         after taking whatever time is necessary to evaluate non-
         traditional alternatives.   
              The Commission proposes to establish the rates for Stage One
         tariffs as follows:
              Derivation of the Embedded Cost Transmission Charge for
              Point-to-Point Service
              To establish firm point-to-point transmission charges, the
         Commission proposes to use the fixed charge methodology that it
         uses to evaluate rate schedule filings.  This methodology is
         available to the public on the Commission's Electric Power Data
         Bulletin Board and has been referenced in various proceedings
         before the Commission. 400/  

         400/ See, e.g., Western Systems Power Pool (WSPP), 55 FERC ¶
              61,099 (1991); Jersey Central Power & Light Company, 38 FERC
              ¶ 61,275 (1987); and UtiliCorp United Inc., 70 FERC ¶ 61,149
              (1995).
         Docket Nos. RM95-8-000
           and RM94-7-001              -296-
              Form No. 1 data are used to develop the cost relationship
         between fixed transmission costs and transmission plant
         investment (a fixed charge rate).  The unit charge is calculated
         by:  (1) dividing plant investment by capability, using the
         annual system peak as a proxy for capability; 401/ and (2)
         multiplying the result by the fixed charge rate.  All data would
         be taken from the Form No. 1 except the return on equity.  
              For the equity return, the Commission proposes to use an
         industry-wide return calculated using the Commission's standard
         discounted cash flow (DCF) analysis of company specific dividend
         yields and an industry average constant growth rate. 402/  As
         an alternative, the Commission could use its DCF method to
         compute company specific equity returns.  However, this is not
         likely to change materially the Stage One rates (e.g., a 1%
         change in the equity return would change the monthly charge by
         about $.08/kW/month, equivalent to an hourly charge of 0.1
         mill/kWh).  We invite comments on this issue.
              We also propose an alternative rate treatment and we ask for
         comment on which we should adopt for all affected public
         utilities.  The alternative is a variation of our fixed charge
         rate method.  Under our alternative proposal, the Commission

         401/ The Commission consistently requires this method for non-
              customer specific rates such as this.  See, e.g., American
              Electric Power Service Company, 67 FERC ¶ 61,168 (1994);
              Kentucky Utilities Company, 67 FERC ¶ 61,189 (1994).
         402/ An industry-wide return on equity calculated using this
              method would currently yield a return of about 11%.
         Docket Nos. RM95-8-000
           and RM94-7-001              -297-
         would multiply an industry-wide transmission fixed charge rate by
         the company-specific investment cost per kW from the Form No. 1.
         403/  This would simplify the process.  In our experience,
         differences in unit charges among companies are due primarily to
         differences in investment cost per kW of capability and not the
         fixed charge rate.  We note that we adopted a similar approach in
         developing cost-based ceiling rates for the WSPP, although we
         developed a single composite rate for WSPP services.
              The following illustrates the computation of a specific
         Stage One point-to-point transmission charge for three utilities
         using the alternative proposal and 1993 Form No. 1 data, Dayton
         Power & Light Company (Dayton), Louisville Gas & Electric Company
         (LGE), and Minnesota Power & Light Company (MPL):
                (1)       (2)          (3)             (4)        
                        Transmission
                        Plant
              Company   in Service  System Peak   Annual Charge
                         (000)          MW        (2)/(3) x 17.5%
         (1)   Dayton    $247,186      2,765         $15.64/kW
         (2)   LGE       $173,836      2,239         $13.59/kW
         (3)   MPL       $162,656      1,252         $22.74/kW

         403/ Based on analyses prepared by the Commission's staff to
              support acceptance of filings tendered by utilities during
              the last two years, a representative transmission fixed
              charge rate is 17.5%.  The Form No. 1 data used to compute a
              company specific investment cost per kW of load is found at
              Page 207, line 69, column g (end of year plant transmission
              plant in service) and Page 401, column D (system peak load)
              of the Form No. 1.
         Docket Nos. RM95-8-000
           and RM94-7-001              -298-
              Under either alternative, the final rule would establish
         specific unit charges.  Charges for shorter term services would
         be derived from the annual charge using standard Commission
         methods:
                   Monthly Charge = Annual Charge/12
                   Weekly Charge  = Annual Charge/52
                   Daily Charge   = Weekly Charge/5
                   Hourly Charge  = Daily Charge/16
         Revenues for daily and hourly service would be capped at the
         equivalent weekly and daily rates pursuant to our standard
         requirements. 404/  
              We propose to establish ceiling rates for non-firm service
         equal to the firm rates, consistent with industry practice.  As a
         practical matter, there is generally a charge for non-firm
         service only in the hours when energy is scheduled and,
         therefore, non-firm service is provided at a discount from firm
         service, which is generally subject to a charge based on
         reservations without regard to actual usage.  As we have
         emphasized in the past, we expect that a rate for firm service
         will be higher than a rate for another service that differs only
         in the degree of firmness. 405/  We also expect that such
         discounts will be offered on a non-discriminatory basis to all

         404/ See Appalachian Power Company, et al., 39 FERC ¶ 61,296 at
              61,965 (1987); WSPP, supra, 55 FERC at 61,321.
         405/ Commonwealth Edison Company, 64 FERC ¶ 61,253 (1993).
         Docket Nos. RM95-8-000
           and RM94-7-001              -299-
         customers and that customers will have sufficient information
         about the availability of discounts (e.g., through an information
         network).
              Derivation of Embedded Cost Charge for Network Service
              To establish network transmission charges, the Commission
         proposes to adopt the load ratio method we approved in Florida
         Municipal Power Agency. 406/  Under this approach, the
         company's annual transmission costs (the product of column (2) in
         the table above for point-to-point service and the same fixed
         charge rate used to develop the point-to-point rates) are
         multiplied by a load ratio percentage.  The load ratio reflects
         the average of the 12 monthly customer coincident peaks divided
         by the average of the 12 monthly total system peaks.  Total
         monthly system peaks for this calculation would reflect all firm
         uses of the transmission system, including the transmission
         owners' own long term firm and unit power sales.  We shall
         specify the annual revenue requirement in the generic tariff and
         direct the transmission provider to insert the load ratio
         computation into the service agreement when filed after a request
         for service is accepted by the utility.     
              Derivation of the Charges for Ancillary Services
              Loss Compensation
              The Commission proposes to establish a loss factor of 3% and
         a charge for energy losses equal to 110% of seller's incremental

         406/ See supra, 67 FERC at 61,481.
         Docket Nos. RM95-8-000
           and RM94-7-001              -300-
         cost.  A 3% loss factor is representative of those in
         transmission agreements on file and a loss compensation charge
         based on the seller's incremental cost is also common.  
              Energy Imbalances
              The Commission proposes to establish an hourly deviation
         band of +/- 1.5% with a minimum of 1 MW per hour and imbalances
         within this band would be returned in kind or subject to a charge
         equal to seller's incremental cost (or a payment equal to
         decremental cost if the public utility transmission provider
         receives too much energy and must compensate the transmission
         customer).  Energy imbalances outside this band would be subject
         to a charge of 100 mills/kWh, the standard industry rate for
         emergency service.  We propose the emergency service charge for
         this purpose because, as with emergency service, the rate should
         provide an incentive to minimize energy imbalances.  We seek
         comment on the size of the deviation band and size of the
         imbalance charge.  
              Scheduling & Dispatching Charges
              The Commission's fixed charge rate methodology which will be
         used to establish the transmission charge includes Account No.
         566, where the costs of transmission related scheduling and
         dispatching are booked.  Accordingly, the generic tariffs would
         include no separate charge for scheduling and dispatching.  This
         should be adequate for most transmission services because most
         customers are likely to require this scheduling and dispatching
         Docket Nos. RM95-8-000
           and RM94-7-001              -301-
         service.  If a customer does not require this service, it may
         propose a different rate treatment by filing a complaint at Stage
         Two.  
              Other Charges
              The other ancillary services -- Load Following, System
         Protection, and Reactive Power -- have a common attribute.  They
         all involve the cost incurred by the transmission provider as a
         result of using generation facilities to support the transmission
         service.  In the past, some or all of these services were often
         provided at a rate reflecting embedded transmission costs, i.e.,
         without a separate charge reflecting the cost of generation
         facilities.  However, the Commission has allowed a 1 mill/kWh
         charge for difficult to quantify costs that served to compensate
         transmission providers for costs like these.  We propose, for
         purposes of the Stage One tariffs, to maintain a ceiling of 1
         mill/kWh as the charge for these three ancillary services on a
         combined basis.  We would expect that the parties would negotiate
         charges below this ceiling if the customer can provide some or
         all of these ancillary services and that this would be filed as a
         change in Stage Two.  We emphasize that, if a utility believes
         that a 1 mill/kWh charge is unsatisfactory, it may file to revise
         the charge under section 205 in Stage Two.  Similarly, if a
         customer finds a 1 mill/kWh charge unsatisfactory, it may file a
         complaint in Stage Two.
         Docket Nos. RM95-8-000
           and RM94-7-001              -302-
                   Questions
              We invite comments on which of the methodologies we should
         adopt.  For example, we are interested in commenters' preference
         for the first alternative, which uses company specific Form No. 1
         data for all inputs, or the second alternative, which uses
         company specific Form No. 1 data only for investment and load.
         With respect to the first alternative, we seek comments on our
         proposal to use an industry-wide equity return for each affected
         public utility and, with respect to the second alternative, we
         seek comments on our proposed uniform 17.5% transmission fixed
         charge rate.  We also seek comments as to whether a more specific
         definition of the load ratio should be adopted, and whether this
         ratio can be used fairly in all situations.  We also invite
         comments on our proposals for ancillary service charges.  All
         comments should take into account our intention to immediately
         put in place generic tariffs so that there will be no delay in
         the availability of nondiscriminatory open access transmission
         services.
                   3.  Ongoing Proceedings
              There are currently a number of ongoing proceedings in which
         the Commission is investigating utilities' open access tariff
         filings.  Concurrently with this order, the Commission is issuing
         a separate order concerning those cases.  
         Docket Nos. RM95-8-000
           and RM94-7-001              -303-
         IV.  REGULATORY FLEXIBILITY ACT
              The Regulatory Flexibility Act (RFA) 407/ requires that
         rulemakings contain either a description and analysis of the
         effect the proposed rule will have on small entities or a
         certification that the rule will not have a substantial economic
         effect on a substantial number of small entities.  Because the
         entities that would be required to comply with the proposed rule
         are public utilities and transmitting utilities that do not fall
         within the RFA's definition of small entities, 408/ the
         Commission certifies that this rule will not have a "significant
         economic impact on a substantial number of small entities."
         V.   ENVIRONMENTAL STATEMENT
              The Commission concludes that promulgating the proposed rule
         would not represent a major federal action having a significant
         adverse impact on the human environment under the Commission's
         regulations implementing the National Environmental Policy Act.
         409/  The proposed rule falls within the categorical
         exemption provided in the Commission's regulations for electric
         rate filings submitted by public utilities under sections 205 and

         407/ 5 U.S.C. §§ 601-612.
         408/ 5 U.S.C. § 601(3) (citing section 3 of the Small Business
              Act, 15 U.S.C. § 632).  Section 3 of the Small Business Act
              defines a "small-business concern" as a business which is
              independently owned and operated and which is not dominant
              in its field of operation.  15 U.S.C. § 632(a).
         409/ 18 CFR Part 380.
         Docket Nos. RM95-8-000
           and RM94-7-001              -304-
         206 of the FPA. 410/  Consequently, neither an environmental
         assessment nor an environmental impact statement is required.
         VI.  INFORMATION COLLECTION STATEMENT
              The Office of Management and Budget's (OMB) regulations
         411/ require that OMB approve certain information and
         recordkeeping requirements imposed by an agency.
              The information collection requirements in the proposed
         regulations are contained in FERC-516, "Electric Rate Filings"
         (OMB approval No. 1902-0096).  The Commission uses the data
         collected in this information collection to carry out its
         responsibilities under Part II of the FPA.  The Commission's
         Office of Electric Power Regulation uses the data to review
         electric rate filings.  The data enable the Commission to examine
         and evaluate the utility's costs and rate of return.
              The Commission is submitting notification of this proposed
         rule to OMB.  Interested persons may obtain information on the
         reporting requirements by contacting the Federal Energy
         Regulatory Commission, 941 North Capitol Street, N.E.,
         Washington, DC 20426 [Attention: Michael Miller, Information
         Services Division, [phone]].  Comments on the requirements
         of the proposed rule can also be sent to the Office of
         Information and Regulatory Affairs of OMB [Attention: Desk
         Officer for Federal Energy Regulatory Commission].

         410/ 18 CFR 380.4(a)(15).
         411/ 5 CFR 1320.13.
         Docket Nos. RM95-8-000
           and RM94-7-001              -305-
         VII. PUBLIC COMMENT PROCEDURES
              The Commission invites comments on the proposed rule from
         interested persons.  An original and 14 copies of written
         comments on the proposed rule must be filed with the Commission
         no later than [insert date 120 days after the date of publication
         in the Federal Register].
              The Commission will also permit interested persons to submit
         reply comments in response to the initial comments filed in this
         proceeding.  Reply comments should be submitted no later than
         [insert date 180 days after the date of publication in the
         Federal Register].
              In addition, commenters are requested to submit a copy of
         their comments on a 3 1/2 inch diskette formatted for MS-DOS
         based computers.  In light of our ability to translate MS-DOS
         based materials, the text need only be submitted in the format
         and version that it was generated (i.e., MS Word, WordPerfect,
         ASCII, etc.).  It is not necessary to reformat word processor
         generated text to ASCII.  For Macintosh users, it would be
         helpful to save the documents in Macintosh word processor format
         and then write them to files on a diskette formatted for MS-DOS
         machines.  All comments should be submitted to the Office of the
         Secretary, Federal Energy Regulatory Commission, 825 North
         Capitol Street, NE, Washington, DC 20426, and should refer to
         Docket Nos. RM95-8-000 and RM94-7-001.
         Docket Nos. RM95-8-000
           and RM94-7-001              -306-
              All written comments will be placed in the Commission's
         public files and will be available for inspection in the
         Commission's public reference room at 941 North Capitol Street,
         NE, Washington, DC, 20426, during regular business hours.
         List of Subjects in 18 CFR Part 35
              Electric power rates, Electric utilities, Reporting and
         recordkeeping requirements.
         By direction of the Commission.  Commissioner Massey concurred in
                                          part and dissented in part with
         ( S E A L )                      a separate statement attached.

                                            Lois D. Cashell,
                                               Secretary.

         Docket Nos. RM95-8-000
           and RM94-7-001              -307-
              In consideration of the foregoing, the Commission proposes
         to amend Part 35, Chapter I, Title 18 of the Code of Federal
         Regulations, as set forth below.
         PART 35 -- FILING OF RATE SCHEDULES
         1.  The authority citation for Part 35 continues to read as
         follows:
              Authority:  16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701;
         42 U.S.C. 7101-7352.
         2.  Part 35 is amended by revising § 35.15, by redesignating §
         35.28 as § 35.29, and by adding new §§ 35.26, 35.27, and 35.28 to
         read as follows:
         § 35.15 - Notices of cancellation or termination.
         (a)  General rule.  When a rate schedule or part thereof required
         to be on file with the Commission is proposed to be cancelled or
         is to terminate by its own terms and no new rate schedule or part
         thereof is to be filed in its place, each party required to file
         the schedule shall notify the Commission of the proposed
         cancellation or termination on the form indicated in § 131.53 of
         this chapter at least sixty days but not more than one hundred-
         twenty days prior to the date such cancellation or termination is
         proposed to take effect.  A copy of such notice to the Commission
         shall be duly posted.  With such notice each filing party shall
         submit a statement giving the reasons for the proposed
         cancellation or termination, and a list of the affected
         purchasers to whom the notice has been mailed.  For good cause
         Docket Nos. RM95-8-000
           and RM94-7-001              -308-
         shown, the Commission may by order provide that the notice of
         cancellation or termination shall be effective as of a date prior
         to the date of filing or prior to the date the filing would
         become effective in accordance with these rules.
         (b)  Applicability.
              (1)  The provisions of paragraph (a) of this section shall
         apply to all contracts for unbundled transmission service and all
         power sale contracts:
              (i) executed prior to [INSERT DATE 90 DAYS AFTER THE FINAL
         RULE IS PUBLISHED IN THE FEDERAL REGISTER]; or
              (ii) if unexecuted, filed with the Commission prior to
         [INSERT DATE 90 DAYS AFTER THE FINAL RULE IS PUBLISHED IN THE
         FEDERAL REGISTER].
              (2)  Any power sales contract executed on or after [INSERT
         DATE 90 DAYS AFTER THE FINAL RULE IS PUBLISHED IN THE FEDERAL
         REGISTER] shall not be subject to the provisions of paragraph (a)
         of this section.
         (c)  Notice.  Any public utility providing jurisdictional
         services under a power sales contract that is not subject to the
         provisions of paragraph (a) of this section shall notify the
         Commission of the date of the cancellation or termination of such
         contract within 30 days after such cancellation or termination
         takes place.
                             *    *    *    *    *    
         Docket Nos. RM95-8-000
           and RM94-7-001              -309-
         § 35.26 - Recovery of Stranded Costs by Public Utilities and
         Transmitting Utilities
         (a)  Purpose.  This section establishes the standards that a
         public utility or transmitting utility must satisfy in order to
         recover stranded costs.
         (b)  Definitions.
              (1)  Wholesale stranded cost means any legitimate, prudent
         and verifiable cost incurred by a public utility or a
         transmitting utility to provide service to:
              (i)  a wholesale requirements customer that subsequently
         becomes, in whole or in part, an unbundled wholesale transmission
         services customer of such public utility or transmitting utility;
         or
              (ii) a retail customer, or a newly created wholesale power
         sales customer, that subsequently becomes, in whole or in part,
         an unbundled wholesale transmission services customer of such
         public utility or transmitting utility.
              (2)  Wholesale requirements customer means a customer for
         whom a public utility or transmitting utility provides by
         contract any portion of its bundled wholesale power requirements.
              (3)  Wholesale transmission services has the same meaning as
         provided in section 3(24) of the Federal Power Act:  the
         transmission of electric energy sold, or to be sold, at wholesale
         in interstate commerce.
         Docket Nos. RM95-8-000
           and RM94-7-001              -310-
              (4)  Wholesale requirements contract means a contract under
         which a public utility or transmitting utility provides any
         portion of a customer's bundled wholesale power requirements.
              (5)  Retail stranded cost means any legitimate, prudent and
         verifiable cost incurred by a public utility or transmitting
         utility to provide service to a retail customer that subsequently
         becomes, in whole or in part, an unbundled retail transmission
         services customer of that public utility or transmitting utility.
              (6)  Retail transmission services means the transmission of
         electric energy sold, or to be sold, in interstate commerce
         directly to a retail customer.
              (7)  New contract means any contract executed after July 11,
         1994, or extended or renegotiated to be effective after July 11,
         1994.
              (8)  Existing contract means any contract executed on or
         before July 11, 1994.
         (c)  Recovery of Wholesale Stranded Costs
              (1)  General requirement.  A public utility or transmitting
         utility will be allowed to seek recovery of wholesale stranded
         costs only as follows:
              (i)  No public utility or transmitting utility may seek
         recovery of wholesale stranded costs if such recovery is
         explicitly prohibited by a contract or settlement agreement, or
         by any power sales or transmission rate schedule or tariff.
         Docket Nos. RM95-8-000
           and RM94-7-001              -311-
              (ii)  If wholesale stranded costs are associated with a new
         wholesale requirements contract containing an exit fee or other
         explicit stranded cost provision, and the seller under the
         contract is a public utility, the public utility may seek
         recovery of such costs, in accordance with the contract, through
         rates for electric energy under sections 205-206 of the FPA.  The
         public utility may not seek recovery of such costs through any
         transmission rate for section 205 or 211 transmission services.
              (iii)  If wholesale stranded costs are associated with a new
         wholesale requirements contract, and the seller under the
         contract is a transmitting utility but not also a public utility,
         the transmitting utility may not seek an order from the
         Commission allowing recovery of such costs.
              (iv)  If wholesale stranded costs are associated with an
         existing wholesale requirements contract, if the seller under
         such contract is a public utility, and if the contract does not
         contain an exit fee or other explicit stranded cost provision,
         the public utility may seek recovery of stranded costs only as
         follows:
              (A)  If either party to the existing contract seeks a
         stranded cost amendment pursuant to a section 205 or section 206
         filing made prior to the expiration of the contract, and the
         Commission accepts or approves an amendment permitting recovery
         of stranded costs, the public utility may seek recovery of such
         costs through section 205 rates for electric energy.
         Docket Nos. RM95-8-000
           and RM94-7-001              -312-
              (B)  If the existing contract is not amended to permit
         recovery of stranded costs as described in paragraph
         (c)(1)(iv)(A) of this section, the public utility may file a
         proposal, prior to the expiration of the contract, to recover
         stranded costs through section 205 or section 211-212 rates for
         wholesale transmission services to the customer.
              (v)  If wholesale stranded costs are associated with an
         existing wholesale requirements contract, if the seller under
         such contract is a transmitting utility but not also a public
         utility, and if the contract does not contain an exit fee or
         other explicit stranded cost provision, the transmitting utility
         may seek recovery of stranded costs through section 211-212
         transmission rates.
              (vi)  If a retail customer becomes a legitimate wholesale
         transmission customer of a public utility or transmitting
         utility, e.g., through municipalization, and costs are stranded
         as a result of the retail-turned-wholesale customer's access to
         wholesale transmission, the utility may seek recovery of such
         costs through section 205 or section 211-212 rates for wholesale
         transmission services to that customer.
              (2)  Evidentiary Demonstration for Wholesale Stranded Cost
         Recovery.  A public utility or transmitting utility seeking to
         recover wholesale stranded costs in accordance with paragraphs
         (c)(1)(iv)-(vi) of this section must demonstrate that:
         Docket Nos. RM95-8-000
           and RM94-7-001              -313-
              (i)  it incurred stranded costs on behalf of its wholesale
         requirements customer or retail customer based on a reasonable
         expectation that the utility would continue to serve the
         customer;
              (ii)  the stranded costs are not more than the customer
         would have contributed to the utility had the customer remained a
         wholesale requirements customer of the utility, or, in the case
         of a retail-turned-wholesale customer, had the customer remained
         a retail customer of utility; and
              (iii)  it has taken and will take reasonable measures to
         mitigate stranded costs.
              (3)  Rebuttable Presumption.  If a public utility or
         transmitting utility seeks recovery of wholesale stranded costs
         associated with an existing contract, as permitted in paragraph
         (c)(1) of this section, and the existing contract contains a
         notice provision, there will be a rebuttable presumption that the
         utility had no reasonable expectation of continuing to serve the
         customer beyond the term of the notice provision.
         (d)  Recovery of Retail Stranded Costs.
              (1)  General requirement.  A public utility may seek to
         recover retail stranded costs through rates for retail
         transmission services only if the state regulatory authority
         does not have authority under state law to address stranded costs
         at the time the retail wheeling is required.
         Docket Nos. RM95-8-000
           and RM94-7-001              -314-
              (2)  Evidentiary Demonstration Necessary for Retail Stranded
         Cost Recovery.  A public utility seeking to recover retail
         stranded costs in accordance with paragraph (d)(1) of this
         section must demonstrate that:
              (i)  it incurred stranded costs on behalf of a retail
         customer that obtains retail wheeling based on a reasonable
         expectation that the utility would continue to serve the
         customer;
              (ii)  the stranded costs are not more than the customer
         would have contributed to the utility had the customer remained a
         retail customer of the utility; and
              (iii)  it has taken and will take reasonable measures to
         mitigate stranded costs.
         § 35.27 -- Power Sales at Market-based Rates
              Notwithstanding any other requirements, any public utility
         seeking authorization to engage in sales for resale of electric
         energy at market-based rates shall not be required to demonstrate
         any lack of market power in generation with respect to sales from
         capacity first placed in service on or after [INSERT DATE 30 DAYS
         AFTER THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER].
         § 35.28 -- Non-discriminatory Open Access Transmission            
                    Tariffs
         (a)  Every public utility owning and/or controlling facilities
         used for the transmission of electric energy in interstate
         commerce must have on file with the Commission no later than
         [INSERT DATE 90 DAYS AFTER THE FINAL RULE IS PUBLISHED IN THE
         Docket Nos. RM95-8-000
           and RM94-7-001              -315-
         FEDERAL REGISTER] tariffs of generally applicability for
         transmission services, including ancillary services, over these
         facilities on both a point-to-point basis and network basis
         consistent with the requirements of Order No. __ (Final Order on
         Open Access and Stranded Costs).
         (b)  Every public utility owning and/or controlling facilities
         used for the transmission of electric energy in interstate
         commerce, but not in existence on [INSERT DATE THE FINAL RULE IS
         PUBLISHED IN THE FEDERAL REGISTER], must file tariffs of
         generally applicability for transmission services, including
         ancillary services, over these facilities on both a point-to-
         point basis and network basis consistent with the requirements of
         Order No. __ (Final Rule on Open Access and Stranded Costs) no
         later than the date any agreement under which such public utility
         would engage in a sale of electric energy at wholesale in
         interstate commerce or the transmission of electric energy in
         interstate commerce is accepted for filing by the Commission.
         (c)  Any public utility that owns and/or controls facilities used
         for the transmission of electric energy in interstate commerce,
         and that uses those facilities to engage in wholesale sales
         and/or purchases of electric energy, must take transmission
         service for such sales and/or purchases under the tariffs filed
         pursuant to paragraph (a) or (b) of this section.
                                                 Appendix  B              
                PRO-FORMA POINT-TO-POINT TRANSMISSION SERVICE TARIFF
                                 TABLE OF CONTENTS
         Preamble
         1.0  Definitions  . . . . . . . . . . . . . . . . . . . . . .   1
              1.1   Ancillary Services . . . . . . . . . . . . . . . .   1
              1.2   Application  . . . . . . . . . . . . . . . . . . .   1
              1.3   Commission . . . . . . . . . . . . . . . . . . . .   1
              1.4   Completed Application  . . . . . . . . . . . . . .   2
              1.5   Control Area . . . . . . . . . . . . . . . . . . .   2
              1.6   Delivering Party . . . . . . . . . . . . . . . . .   2
              1.7   Designated Agent . . . . . . . . . . . . . . . . .   2
              1.8   Direct Assignment Facilities . . . . . . . . . . .   3
              1.9   Eligible Customer  . . . . . . . . . . . . . . . .   3
              1.10  Facilities Study   . . . . . . . . . . . . . . . .   3
              1.11  Firm Transmission Service  . . . . . . . . . . . .   3
              1.12  Good Utility Practice  . . . . . . . . . . . . . .   4
              1.13  Hourly Non-Firm Transmission Service . . . . . . .   4
              1.14  Native Load Customers  . . . . . . . . . . . . . .   5
              1.15  Network Customers  . . . . . . . . . . . . . . . .   5
              1.16  Network Upgrades . . . . . . . . . . . . . . . . .   5
              1.17  Non-Firm Transmission Service  . . . . . . . . . .   5
              1.18  Parties  . . . . . . . . . . . . . . . . . . . . .   6
              1.19  Point(s) of Delivery . . . . . . . . . . . . . . .   6
              1.20  Point(s) of Receipt  . . . . . . . . . . . . . . .   6
              1.21  Point-to-Point Transmission Service  . . . . . . .   6
              1.22  Receiving Party  . . . . . . . . . . . . . . . . .   6
              1.23  Regional Transmission Groups . . . . . . . . . . .   6
              1.24  Reserved Capacity  . . . . . . . . . . . . . . . .   7
              1.25  Service Agreement  . . . . . . . . . . . . . . . .   7
              1.26  Service Commencement Date  . . . . . . . . . . . .   7
              1.27  Short-Term Firm Transmission Service . . . . . . .   7
              1.28  Short-Term Non-Firm Transmission Service . . . . .   8
              1.29  System Impact Study  . . . . . . . . . . . . . . .   8
              1.30  Transmission Customer  . . . . . . . . . . . . . .   8
              1.31  Transmission Provider  . . . . . . . . . . . . . .   8
              1.32  Transmission Service . . . . . . . . . . . . . . .   8
              1.33  Transmission System  . . . . . . . . . . . . . . .   9
              1.34  Valid Request  . . . . . . . . . . . . . . . . . .   9
         2.0  Nature of Firm Transmission Service  . . . . . . . . . .   9
              2.1   Term . . . . . . . . . . . . . . . . . . . . . . .   9
              2.2   Service Priority . . . . . . . . . . . . . . . . .   9
              2.3   Use of Firm Service by the Transmission Provider .   9
              2.4   Service Agreements . . . . . . . . . . . . . . . .  10
              2.5   Transmission Customer Obligations for Facility
                    Additions or Redispatch Costs  . . . . . . . . . .  10
              2.6   Curtailment of Service . . . . . . . . . . . . .    11
              2.7   Classification of Firm Transmission Service  . . .  12
         3.0  Nature of Non-Firm Transmission Service  . . . . . . . .  16
                                         i
              3.1   Term . . . . . . . . . . . . . . . . . . . . . . .  16
              3.2   Service Priority . . . . . . . . . . . . . . . . .  16
              3.3   Use of Non-Firm Transmission Service by the
                    Transmission Provider  . . . . . . . . . . . . . .  17
              3.4   Service Agreements . . . . . . . . . . . . . . . .  17
              3.5   Classifications of Non-Firm Transmission Service .  18
              3.6   Scheduling of Non-Firm Transmission  . . . . . .    18
              3.7   Curtailment of Service . . . . . . . . . . . . . .  19
         4.0  Service Availability . . . . . . . . . . . . . . . . . .  21
              4.1   General Conditions . . . . . . . . . . . . . . . .  21
              4.2   Determination of Capacity Availability . . . . . .  21
              4.3   Initiating Service in the Absence of an
                    Executed Service Agreement . . . . . . . . . . . .  22
              4.4   Obligation to Expand or Modify Facilities  . . . .  23
              4.5   Other Transmission Service Schedules . . . . . . .  23
         5.0  Real Time Information Network Requirements . . . . . . .  24
         6.0  Standards of Conduct . . . . . . . . . . . . . . . . . .  24
              6.1   Standard of Nondiscrimination  . . . . . . . . . .  24
              6.2   Communications with Eligible Customers . . . . . .  24
              6.3   Standard of Due Diligence  . . . . . . . . . . . .  24
              6.4   Dispute Resolution Procedures  . . . . . . . . . .  25
         7.0  Conditions Required of Transmission Customers  . . . . .  25
         8.0  Ancillary Services . . . . . . . . . . . . . . . . . . .  26
              8.1   Loss Compensation Service  . . . . . . . . . . . .  27
              8.2   Load Following Service . . . . . . . . . . . . . .  27
              8.3   System Protection Service  . . . . . . . . . . . .  27
              8.4   Energy Imbalance Service . . . . . . . . . . . . .  27
              8.5   Reactive Power/Voltage Control Service . . . . . .  27
              8.6   Scheduling and Dispatching Service . . . . . . . .  27
         9.0  Procedures for Arranging Firm Service  . . . . . . . . .  27
              9.1   Application  . . . . . . . . . . . . . . . . . . .  27
              9.2   Completed Application  . . . . . . . . . . . . . .  28
              9.3   Deposit  . . . . . . . . . . . . . . . . . . . . .  29
              9.4   Notice of Deficient Application  . . . . . . . . .  30
              9.5   Response to Valid Requests . . . . . . . . . . . .  31
              9.6   Tendering of Service Agreement . . . . . . . . . .  31
              9.7   Extensions for Commencement of Service . . . . . .  32
              9.8   Termination of Service . . . . . . . . . . . . . .  33
         10.0 Procedures for Arranging Non-Firm Transmission Service    34
              10.1  Application  . . . . . . . . . . . . . . . . . . .  34
              10.2  Completed Application  . . . . . . . . . . . . . .  34
              10.3  Reservation of Non-Firm Transmission Service . . .  35
              10.4  Determination of Capacity Availability . . . . . .  36
              10.5  Charges For Schedule Changes . . . . . . . . . . .  36
              10.6  Transmission Customer Responsibility for
                                         ii
                    Third-Party Arrangements . . . . . . . . . . . . .  37
         11.0 Determination of Capacity Availability and
              Responsibility for Costs Incurred in Providing Firm
              Transmission Service . . . . . . . . . . . . . . . . . .  37
              11.1  Notice of Need for System Impact Study . . . . . .  37
              11.2  Study Agreement and Cost Reimbursement . . . . . .  38
              11.3  Performance of System Impact Study . . . . . . . .  40
              11.4  Initial Allocation of Available Capacity . . . . .  41
              11.5  Determining Need for New Facilities  . . . . . . .  41
              11.6  Tendering of Service Agreement in the Absence of
                    Need for New Facilities  . . . . . . . . . . . . .  42
              11.7  Tendering of Facilities Study Agreement Where
                    Construction of New Facilities is Contemplated . .  43
              11.8  Due Diligence in Completing New Facilities . . . .  44
              11.9  Partial Interim Service  . . . . . . . . . . . . .  44
              11.10 Facilities Study Modifications . . . . . . . . . .  45
              11.11 Expedited Procedures for New Facilities  . . . . .  46
         12.0 Procedures if Transmission Provider is Unable to
              Complete New Transmission Facilities for Firm
              Transmission Service . . . . . . . . . . . . . . . . . .  47
              12.1  Delays or Constraints in Construction of New
                    Facilities . . . . . . . . . . . . . . . . . . . .  47
              12.2  Alternatives to Constrained Facility Additions . .  47
              12.3  Refund Obligation for Constrained Facility
                    Additions  . . . . . . . . . . . . . . . . . . . .  48
         13.0 Provisions Relating to Transmission Construction and
              Services on the Systems of Other Utilities . . . . . . .  49
              13.1  Responsibility for Third-Party System Additions  .  49
              13.2  Coordination of Third-Party System Additions . . .  49
         14.0 Changes in Service Specifications  . . . . . . . . . . .  50
              14.1  Modifications On a Non-Firm Basis  . . . . . . . .  50
              14.2  Modifications On a Firm Basis  . . . . . . . . . .  52
         15.0 Sale or Assignment of Transmission Service . . . . . . .  52
              15.1  Procedures for Assignment or Transfer of Service .  52
              15.2  Limitations on Assignment or Transfer of Service .  53
              15.3  Information on Assignment or Transfer of Service .  54
         16.0 Metering and Power Factor Correction   . . . . . . . . .  54
              16.1  Transmission Customer Obligations  . . . . . . . .  54
              16.2  Transmission Provider Access to Metering Data  . .  54
              16.3  Power Factor . . . . . . . . . . . . . . . . . . .  55
         17.0 Compensation for Transmission Service  . . . . . . . . .  55
         18.0 Other Charges  . . . . . . . . . . . . . . . . . . . . .  55
              18.1  Stranded Cost Recovery . . . . . . . . . . . . . .  55
              18.2  Termination Charge . . . . . . . . . . . . . . . .  55
                                        iii
         19.0 Compensation for New Facilities and Redispatch Costs . .  56
         20.0 Booking of Revenues Attributable to The Transmission
              Provider's Use of this Tariff. . . . . . . . . . . . . .  56
         21.0 Billing and Payment  . . . . . . . . . . . . . . . . . .  57
              21.1  Billing Procedure  . . . . . . . . . . . . . . . .  57
              21.2  Interest on Unpaid Balances  . . . . . . . . . . .  57
              21.3  Customer Default . . . . . . . . . . . . . . . . .  58
         22.0 Regulatory Filings . . . . . . . . . . . . . . . . . . .  59
         23.0 Liability and Indemnification  . . . . . . . . . . . . .  59
         24.0 Creditworthiness . . . . . . . . . . . . . . . . . . . .  60
         25.0 Dispute Resolution Procedures  . . . . . . . . . . . . .  61
              25.1  Internal Dispute Resolution Procedures . . . . . .  61
              25.2  External Arbitration Procedures  . . . . . . . . .  62
              25.3  Arbitration Decisions  . . . . . . . . . . . . . .  63
              25.4  Costs  . . . . . . . . . . . . . . . . . . . . . .  63
              25.5  Rights Under The Federal Power Act . . . . . . . .  64
         Schedule FTS - Firm Transmission Service  . . . . . . . . . .  65
         Schedule STNF - Short-Term Non-Firm Transmission Service  . .  66
         Schedule HNF - Hourly Non-Firm Transmission Service . . . . .  67
         Schedule 1 - Loss Compensation Service  . . . . . . . . . . .  68
         Schedule 2 - Load Following Service . . . . . . . . . . . . .  69
         Schedule 3 - System Protection Service  . . . . . . . . . . .  71
         Schedule 4 - Energy Imbalance Service . . . . . . . . . . . .  73
         Schedule 5 - Reactive Power/Voltage Control Service . . . . .  75
         Schedule 6 - Scheduling and Dispatching Service . . . . . . .  77
         Appendix A - Methodology to Assess Transfer Capacity
                      Available  . . . . . . . . . . . . . . . . . . .  79
         Appendix B - Form of Service Agreement - FTS  . . . . . . . .  80
         Appendix C - Form of Service Agreement - STNF . . . . . . . .  84
         Appendix D - Methodology for Completing a System
                      Impact Study . . . . . . . . . . . . . . . . . .  86
         Index of Customers under FERC Point-To-Point Transmission
         Service Tariff  . . . . . . . . . . . . . . . . . . . . . . .  87
                                         iv
                                        Point-To-Point Transmission Tariff
                                                      Original Sheet No. 1
         POINT-TO-POINT TRANSMISSION SERVICE TARIFF
         Preamble
              The Transmission Provider will provide firm and non-firm
         Point-to-Point Transmission Service pursuant to the terms and
         conditions of this tariff (Tariff). The service that the
         Transmission Provider will provide under this Tariff is for the
         receipt of capacity and energy at designated Point(s) of Receipt
         and the transmission of such capacity and energy to designated
         Point(s) of Delivery.  As an alternative to receiving service
         from the Point(s) of Receipt to the Point(s) of Delivery, the
         Transmission Customer may request the Transmission Provider to
         provide transmission service on a non-firm, capacity-available
         basis, between Secondary Point(s) of Receipt or Delivery in
         accordance with the provisions of this Tariff.
         1.0   Definitions
              1.1  Ancillary Services:  Ancillary services are those
                   services necessary to support the transmission of
                   energy from resources to loads while maintaining
                   reliable operation of the Transmission Provider's
                   transmission system in accordance with Good Utility
                   Practice.
              1.2  Application:  A request by an Eligible Customer for
                   transmission service pursuant to the provisions of this
                   Tariff.
              1.3  Commission:  The Federal Energy Regulatory Commission.
                                        Point-To-Point Transmission Tariff
                                                      Original Sheet No. 2
              1.4  Completed Application:  An Application that satisfies
                   all of the information and other requirements,
                   including any required deposit, of this Tariff.
              1.5  Control Area:  An electric power system or combination
                   of electric power systems to which a common automatic
                   generation control scheme is applied in order to:
                   (1)  match, at all times, the power output of the
                        generators within the electric power system(s) and
                        capacity and energy purchased from entities
                        outside the electric power system(s), with the
                        load within the electric power system(s);
                   (2)  maintain, within the limits of Good Utility
                        Practice, scheduled interchange with other Control
                        Areas;
                   (3)  maintain the frequency of the electric power
                        system(s) within reasonable limits in accordance
                        with Good Utility Practice; and
                   (4)  provide sufficient generating capacity to maintain
                        operating reserves in accordance with Good Utility
                        Practice.  
              1.6  Delivering Party:  The entity supplying the capacity
                   and/or energy to be transmitted at Point(s) of Receipt.
              1.7  Designated Agent:  Any entity that performs actions or
                   functions on behalf of the Transmission Provider, an
                   Eligible Customer, or the Transmission Customer
                   required under this Tariff.
                                        Point-To-Point Transmission Tariff
                                                      Original Sheet No. 3
              1.8  Direct Assignment Facilities:  Facilities that have
                   been or are constructed (or caused to be constructed)
                   by the Transmission Provider for the sole use/benefit
                   of facilitating a request for service by a particular
                   Transmission Customer under this Tariff, the costs of
                   which the Commission permits to be directly assigned to
                   the Transmission Customer.  Direct Assignment
                   Facilities shall be specified in the Service Agreement
                   that governs service to the Transmission Customer.
              1.9  Eligible Customer:  Any of the following:  (i) the
                   Transmission Provider (for its own point-to-point
                   transmission use of the transmission system); (ii) any
                   electric utility, Federal power marketing agency, or
                   any other person generating electric energy for sale
                   for resale; and (iii) any designated agent for an
                   Eligible Customer.
              1.10 Facilities Study:  An engineering study conducted by
                   the Transmission Provider to determine the required
                   modifications to the Transmission Provider's
                   Transmission System, including the cost and scheduled
                   completion date for such modifications, that will be
                   required to provide a requested transmission service in
                   accordance with the results of the System Impact Study.
              1.11 Firm Transmission Service:  Point-to-point transmission
                   service under this Tariff that is reserved and/or
                   scheduled for a term of one year or more and that is of
                                        Point-To-Point Transmission Tariff
                                                      Original Sheet No. 4
                   the same priority as that of the Transmission
                   Provider's firm use of the transmission system.  Firm
                   Transmission Service under this Tariff that is reserved
                   and/or scheduled for a term of less than one year shall
                   be considered to be Short-Term Firm Transmission
                   Service for purposes of service availability.
              1.12 Good Utility Practice:  Any of the practices, methods
                   and acts engaged in or approved by a significant
                   portion of the electric utility industry during the
                   relevant time period, or any of the practices, methods
                   and acts which, in the exercise of reasonable judgment
                   in light of the facts known at the time the decision
                   was made, could have been expected to accomplish the
                   desired result of the lowest reasonable cost consistent
                   with good business practices, reliability, safety and
                   expedition.  Good Utility Practice is not intended to
                   be limited to the optimum practice, method, or act to
                   the exclusion of all others, but rather to be
                   acceptable practices, methods, or acts generally
                   accepted in the region and consistently adhered to by
                   the Transmission Provider.
              1.13 Hourly Non-Firm Transmission Service:  Point-to-point
                   transmission service under this Tariff that is
                   scheduled and paid for on an as available basis and is
                   subject to interruption.
                                        Point-To-Point Transmission Tariff
                                                      Original Sheet No. 5
              1.14 Native Load Customers:  The wholesale and retail
                   customers on whose behalf the Transmission Provider, by
                   statute, franchise, regulatory requirements, or
                   contract, has undertaken an obligation to construct and
                   operate the Transmission Provider's system to meet the
                   reliable electric needs of such customers.  
              1.15 Network Customers:  Entities receiving transmission
                   service pursuant to the terms of the Transmission
                   Provider's Network Integration Tariff.
              1.16 Network Upgrades:  Modifications and/or additions to
                   transmission-related facilities that are integrated
                   with and support the Transmission Provider's overall
                   Transmission System for the general benefit of all
                   users of such Transmission System.  
              1.17 Non-Firm Transmission Service:  Point-to Point
                   transmission service under this Tariff that is reserved
                   and/or scheduled on an as available basis and is
                   subject to interruption.  Non-firm Transmission Service
                   is available on a stand alone basis as either Hourly
                   Non-firm Transmission Service or Short-Term Non-firm
                   Transmission Service.  Non-firm Transmission Service is
                   also available in conjunction with reservations of Firm
                   Transmission Service for any term subject to the
                   conditions set forth in Section 14.1 under this Tariff.
                                        Point-To-Point Transmission Tariff
                                                      Original Sheet No. 6
              1.18 Parties:  The Transmission Provider and the
                   Transmission Customer receiving service under this
                   Tariff.
              1.19 Point(s) of Delivery:  Point(s) of interconnection on
                   the Transmission Provider's Transmission System where
                   capacity and/or energy transmitted by the Transmission
                   Provider will be made available to the Receiving Party.
                   The Point(s) of Delivery shall be specified in the
                   Service Agreement.
              1.20 Point(s) of Receipt:  Point(s) of interconnection on
                   the Transmission Provider's Transmission System where
                   capacity and/or energy will be made available to the
                   Transmission Provider by the Delivering Party.  The
                   Point(s) of Receipt shall be specified in the Service
                   Agreement.
              1.21 Point-to-Point Transmission Service:  The reservation
                   and/or transmission of energy on either a firm basis
                   and/or non-firm basis from the Point(s) of Receipt to
                   the Point(s) of Delivery under this Tariff, including
                   any Ancillary Services that are provided by the
                   Transmission Provider in conjunction with such service.
              1.22 Receiving Party:  The entity receiving the capacity
                   and/or energy transmitted by the Transmission Provider
                   to Point(s) of Delivery.
              1.23 Regional Transmission Group:  A voluntary organization
                   of transmission owners, transmission users and other
                                        Point-To-Point Transmission Tariff
                                                      Original Sheet No. 7
                   entities approved by the Commission to efficiently
                   coordinate transmission planning (and expansion),
                   operation and use on a regional (and interregional)
                   basis.
              1.24 Reserved Capacity:  The maximum amount of capacity
                   and/or energy that the Transmission Provider agrees to
                   transmit for the Transmission Customer over the
                   Transmission Provider's Transmission System between the
                   Point(s) of Receipt and the Point(s) of Delivery.
                   Reserved Capacity shall be expressed in terms of whole
                   megawatts on a sixty (60) minute interval (commencing
                   on the clock hour) basis.
              1.25 Service Agreement:  The initial agreement and any
                   supplements thereto entered into by the Transmission
                   Customer and the Transmission Provider for service
                   under this Tariff.
              1.26 Service Commencement Date:  The date the Transmission
                   Provider begins to provide service pursuant to the
                   terms of an executed Service Agreement, or the date the
                   Transmission Provider begins to provide service in
                   accordance with the provisions of section 4.3 of this
                   Tariff.
              1.27 Short-Term Firm Transmission Service:  Firm point-to-
                   point transmission service under this Tariff that is
                   reserved and/or scheduled for a term of less than one
                   year and that is of the same priority as that of the
                                        Point-To-Point Transmission Tariff
                                                      Original Sheet No. 8
                   Transmission Provider's firm use of the transmission
                   system.  
              1.28 Short-Term Non-Firm Transmission Service:  Non-firm
                   point-to-point transmission service under this Tariff
                   that is reserved and/or scheduled on a daily, weekly,
                   or monthly basis for renewable terms of not more than
                   thirty (30) days each and is subject to interruption.  
              1.29 System Impact Study:  An assessment by the Transmission
                   Provider of (i) the adequacy of the Transmission System
                   to accommodate a request for firm Transmission Service
                   and/or (ii) any costs for system redispatch, Direct
                   Assignment Facilities or Network Upgrades that would be
                   incurred in order to provide transmission service.
              1.30 Transmission Customer:  Any Eligible Customer (or its
                   designated agent) that executes a service agreement
                   and/or receives transmission service under this Tariff.
              1.31 Transmission Provider:  The public utility (or its
                   designated agent) that owns or controls facilities used
                   for the transmission of electric energy in interstate
                   commerce and provides transmission service under this
                   Tariff.
              1.32 Transmission Service:  Point-to-point transmission
                   service provided under this Tariff.  Transmission
                   service will be provided on a firm and/or non-firm
                   basis.
                                        Point-To-Point Transmission Tariff
                                                      Original Sheet No. 9
              1.33 Transmission System:  The facilities owned, controlled,
                   operated or supported by the Transmission Provider that
                   are used to provide transmission service under this
                   Tariff.
              1.34 Valid Request:  A Completed Application that satisfies
                   on an ongoing basis all of the requirements of the
                   Tariff.
         2.0   Nature of Firm Transmission Service
              2.1  Term - The minimum term of firm Transmission Service
                   shall be one hour (or a reasonable period that is
                   generally accepted in the region and consistently
                   adhered to by the Transmission Provider) and there
                   shall be no maximum term.
              2.2  Service Priority - An Application for firm Transmission
                   Service will have priority over an Application for non-
                   firm Transmission Service under this Tariff.  Firm
                   Transmission Service will always have priority over
                   non-firm transmission service under this Tariff.  All
                   firm transmission service provided under the Network
                   Integration and Point-To-Point Transmission Service
                   Tariffs will have equal priority.
              2.3  Use of the Firm Service by the Transmission Provider -
                   The Transmission Provider will take service under this
                   Tariff when providing itself firm Transmission Service
                   for off-system or third-party sales.  With respect to
                   any firm off-system or third-party wholesale sale made
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                                                     Original Sheet No. 10
                   pursuant to an agreement that is in effect on the date
                   this Tariff becomes effective, the Transmission
                   Provider will be subject to the same procedures
                   governing determination and allocation of available
                   capacity, scheduling, and curtailment priorities for
                   such sale as is applicable to any Completed Application
                   and/or Valid Request for firm Transmission Service and
                   any firm Transmission Service provided under this
                   Tariff.  The Transmission Provider also will maintain
                   separate accounting for its use of the Tariff to make
                   firm off-system or third-party sales.
              2.4  Service Agreements - The Transmission Provider shall
                   offer a standard form Service Agreement to an Eligible
                   Customer when it submits a Completed Application for
                   firm Transmission Service pursuant to this Tariff.
                   Executed Service Agreements that contain the
                   information required under this Tariff shall be filed
                   with the Commission in compliance with applicable
                   Commission regulations.  
              2.5  Transmission Customer Obligations for Facility
                   Additions or Redispatch Costs - In cases where the
                   Transmission Provider determines that existing capacity
                   on the Transmission System is not adequate to provide
                   firm Transmission Service without (1) degrading or
                   impairing the reliability of service to Native Load
                   Customers, Network Customers and other Transmission
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                                                     Original Sheet No. 11
                   Customers, or (2) interfering with the Transmission
                   Provider's ability to meet prior firm contractual
                   commitments to others, the obligation to provide firm
                   Transmission Service upon expansion or upgrading of the
                   Transmission Provider's Transmission System pursuant to
                   the terms of Section 4.4 of this Tariff shall be
                   subject to the Transmission Customer agreeing to
                   compensate the Transmission Provider for transmission
                   facility additions pursuant to the terms of Section 19
                   of this Tariff.  To the extent the Transmission
                   Provider can relieve any system constraint more
                   economically by redispatching its system than through
                   constructing Network Upgrades, it shall do so, provided
                   that the Eligible Customer agrees to compensate the
                   Transmission Provider pursuant to the terms of Section
                   19 of this Tariff.  
              2.6  Curtailment of Service - The Transmission Provider
                   shall provide firm Transmission Service with the same
                   curtailment priority that it provides to Native Load
                   Customers and Network Customers.  In the event that a
                   curtailment on the Transmission Provider's Transmission
                   System, or a portion thereof, is required to maintain
                   reliable operation of such system, curtailment of firm
                   Transmission Service will be proportionally allocated
                   among the Transmission Provider's Native Load
                   Customers, Network Customers, and Transmission
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                                                     Original Sheet No. 12
                   Customers taking firm Transmission Service under this
                   Tariff when such proportional curtailments can be
                   reasonably accommodated consistent with Good Utility
                   Practice.  The Transmission Provider will notify all
                   affected Transmission Customers in a timely manner of
                   any scheduled interruption (e.g., scheduled
                   maintenance).  When the Transmission Provider
                   determines that an electrical emergency exists on its
                   Transmission System and implements emergency procedures
                   to curtail firm transmission service, the Transmission
                   Customer shall make the required reductions upon
                   request of the Transmission Provider.  However, the
                   Transmission Provider reserves the right to interrupt,
                   in whole or in part, firm Transmission Service provided
                   under this Tariff when, in the Transmission Provider's
                   sole discretion, an emergency or other unforeseen
                   condition impairs or degrades the reliability of its
                   transmission system.
              2.7  Classification of Firm Transmission Service -
                   (a)  Firm Transmission Service under this Tariff shall
                        be point-to-point Transmission Service, although
                        the Transmission Customer may (1) change its
                        Receipt and Delivery Points to obtain service on a
                        non-firm basis consistent with the terms of
                        Section 14.1 of this Tariff or (2) request a
                        modification of the Points of Receipts and/or
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                                                     Original Sheet No. 13
                        Delivery on a firm basis pursuant to the terms of
                        Section 14.2 of this Tariff.
                   (b)  A Transmission Customer (including the
                        Transmission Provider for its sales subject to
                        this Tariff) may purchase transmission service to
                        make sales of power from multiple generating units
                        that are on the Transmission Provider's
                        Transmission System.  For such a purchase of
                        transmission service, the resources will be
                        designated as multiple Points of Receipt.  The
                        Transmission Customer (including the Transmission
                        Provider for sales subject to this Tariff) will be
                        required to provide to the Transmission Provider
                        the information identified in Section 9.2 of this
                        Tariff.
                   (c)  The Transmission Provider shall provide firm
                        deliveries of power from the Point(s) of Receipt
                        to the Point(s) of Delivery.  Each Point of
                        Receipt at which firm transmission capacity is
                        reserved by the Transmission Customer shall be set
                        forth in the Service Agreement along with a
                        corresponding capacity reservation associated with
                        each Point of Receipt.  Each Point of Delivery at
                        which firm transmission capacity is reserved by
                        the Transmission Customer shall be set forth in
                        the Service Agreement along with a corresponding
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                                                     Original Sheet No. 14
                        capacity reservation associated with each Point of
                        Delivery.  The greater of either (1) the sum of
                        the capacity reservations at the Points(s) of
                        Receipt, or (2) the sum of the capacity
                        reservations at the Points(s) of Delivery shall be
                        the Transmission Customer's Reserved Capacity.
                        The Transmission Customer will be billed for its
                        Reserved Capacity under the terms of Schedule FTS
                        Firm Transmission Service, which is attached to
                        and is a part of this Tariff.  The Transmission
                        Customer may not exceed its firm Reserved Capacity
                        at each Point of Receipt and each Point of
                        Delivery except as otherwise specified in Section
                        14 of this Tariff.  The Transmission Provider
                        shall specify the rate treatment and all related
                        terms and conditions applicable in the event that
                        a Transmission Customer (including the
                        Transmission Provider) exceeds its firm reserved
                        capacity at any Point of Receipt and Point of
                        Delivery.
                   (d)  Schedules for the Transmission Customer's firm
                        Transmission Service must be submitted to the
                        Transmission Provider no later than 10:00 a.m. or
                        a reasonable time that is generally accepted in
                        the region and is consistently adhered to by the
                        Transmission Provider of the day prior to
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                                                     Original Sheet No. 15
                        commencement of such service.  Schedules submitted
                        less than one day in advance will be accommodated,
                        if practicable.  Hour-to-hour schedules of any
                        power and energy that is to be delivered must be
                        stated in increments of 1,000 kW per hour.
                        Transmission Customers within the Transmission
                        Provider's service area with multiple requests for
                        transmission service at a Point of Receipt, each
                        of which is under 1,000 kW per hour, may
                        consolidate their service requests at the point of
                        receipt into units of 1,000 kW per hour for
                        scheduling and billing purposes.  Scheduling
                        changes will be permitted up to 20 minutes or a
                        reasonable time that is generally accepted in the
                        region and is consistently adhered to by the
                        Transmission Provider before the start of the next
                        clock hour where the Delivering Party also agrees
                        to the schedule modification.  The Transmission
                        Provider will furnish to dispatchers on the system
                        of the Delivering Party hour-to-hour schedules
                        equal to those furnished by the Receiving Party
                        and shall deliver power and energy at the Point(s)
                        of Delivery in an amount provided by such
                        schedules.  Should the Transmission Customer,
                        Delivering Party or Receiving Party revise or
                        terminate any schedule pursuant to its contract
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                                                     Original Sheet No. 16
                        authority to do so, such party shall immediately
                        notify the Transmission Provider, and the
                        Transmission Provider shall have the right to
                        adjust accordingly the schedule for capacity and
                        energy to be received and to be delivered.   
         3.0   Nature of Non-Firm Transmission Service
              3.1  Term - Non-firm Transmission Service will be available
                   for periods ranging from hourly to thirty (30) days.
                   However, a Purchaser of Short-Term Non-Firm
                   Transmission Service will be entitled to reserve
                   sequential terms of service (such as sequential monthly
                   terms) so that the total time period for which the
                   reservation applies is greater than 30 days, subject to
                   the requirements of Section 10.3 of this Tariff, or
                   such reasonable terms that are generally accepted in
                   the region and are consistently adhered to by the
                   Transmission Provider.
              3.2  Service Priority - Non-firm Service shall be available
                   on a first-come, first-served basis (i.e., in the
                   chronological sequence in which each Transmission
                   Customer has reserved service) from capacity in excess
                   of that needed for reliable service to Native Load
                   Customers, Network Customers and other Transmission
                   Customers taking Firm and Short-Term Firm Transmission
                   Service under this Tariff.
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                                                     Original Sheet No. 17
              3.3  Use of Non-Firm Transmission Service by the
                   Transmission Provider - The Transmission Provider will
                   be subject to the rates and terms and conditions of
                   service under this Tariff when the Transmission
                   Provider provides itself non-firm Transmission Service
                   in making any non-firm wholesale sale pursuant to a
                   contract entered into following the date this Tariff is
                   accepted for filing by the Commission.  With respect to
                   any non-firm wholesale sale made pursuant to a
                   coordination agreement existing on the date this Tariff
                   is accepted for filing, the Transmission Provider will
                   be subject to the same procedures governing scheduling
                   and curtailment as are applicable to any non-firm
                   Transmission Service requested and provided under this
                   Tariff.  The Transmission Provider also will maintain
                   separate accounting for its use of the Tariff to make
                   non-firm off-system or third-party sales.
              3.4  Service Agreements - The Transmission Provider shall
                   offer a standard form Service Agreement to an Eligible
                   Customer when it submits a Completed Application for
                   Non-firm Transmission Service pursuant to this Tariff.
                   Executed Service Agreements that contain the
                   information required under this Tariff shall be filed
                   with the Commission in compliance with applicable
                   Commission regulations.  
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 18
              3.5  Classifications of Non-Firm Transmission Service - Non-
                   firm Transmission Service shall be point-to-point
                   Transmission Service.  Parties requesting non-firm
                   service for the transmission of firm power do so at
                   their own risk and with the full realization that such
                   service is subject to interruption under the terms of
                   this Tariff.  Non-firm Transmission Service shall
                   include:
                   (i)  Hourly Transmission Service - Transmission of
                        energy on an hourly basis under Schedule HNF.
                   (ii) Short-Term Transmission Service - Transmission of
                        scheduled short-term capacity and energy on a
                        weekly or daily basis but not to exceed thirty
                        (30) days in duration for any one Application for
                        non-firm service under this Tariff under Schedule
                        STNF.
              3.6  Scheduling of Non-Firm Transmission - Schedules for the
                   Transmission Customer's non-firm Transmission Service
                   must be submitted to the Transmission Provider no later
                   than 2:00 p.m. or a reasonable time that is generally
                   accepted in the region and is consistently adhered to
                   by the Transmission Provider of the day prior to
                   commencement of such service.  Schedules submitted
                   after 2:00 p.m. will be accommodated, if practicable.
                   Hour-to-hour schedules of energy that is to be
                   delivered must be stated in increments of 1,000 kW per
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                                                     Original Sheet No. 19
                   hour.  Transmission Customers within the Transmission
                   Provider's service area with multiple requests for
                   transmission service at a Point of Receipt, each of
                   which is under 1,000 kW per hour, may consolidate their
                   schedules at the point of receipt into units of 1,000
                   kW per hour.  Scheduling changes will be permitted up
                   to 20 minutes or a reasonable time that is generally
                   accepted in the region and is consistently adhered to
                   by the Transmission Provider before the start of the
                   next clock hour where the Delivering Party also agrees
                   to the schedule modification.  The Transmission
                   Provider will furnish to dispatchers on the system of
                   the Delivering Party hour-to-hour schedules equal to
                   those furnished by the Receiving Party and shall
                   deliver power and energy at the Point(s) of Delivery in
                   an amount provided by such schedules.  Should the
                   Transmission Customer, Delivering Party or Receiving
                   Party revise or terminate any schedule, such party
                   shall immediately notify the Transmission Provider.
              3.7  Curtailment of Service - The Transmission Provider
                   reserves the right to interrupt, in whole or in part,
                   non-firm Transmission Service provided under this
                   Tariff when, in the Transmission Provider's sole
                   discretion, an emergency or other unforeseen condition
                   impairs or degrades the reliability of its Transmission
                   System, when necessary to provide reliable service to
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                                                     Original Sheet No. 20
                   Native Load Customers and Network Customers, and/or
                   when necessary to meet the needs of Transmission
                   Customers taking firm Transmission Service under this
                   Tariff.  In such situations, all non-firm Transmission
                   Service will be curtailed before firm Transmission
                   Service is curtailed.  The Transmission Provider also
                   will discontinue or reduce service to the Transmission
                   Customer to the extent that deliveries for transmission
                   are discontinued or reduced at the Point(s) of Receipt.
                   Where curtailments are required, curtailments will
                   first be made to transactions of the shortest term
                   (e.g., hourly non-firm transactions will be curtailed
                   before daily non-firm transactions, daily non-firm
                   transactions will be curtailed before weekly non-firm
                   transactions).  All curtailments will be made on a non-
                   discriminatory basis including the Transmission
                   Provider's own use of the Transmission System for all
                   its off-system non-firm wholesale sales.  The
                   Transmission Provider will provide advanced notice of
                   curtailments where such notice can be provided
                   consistent with Good Utility Practice.  In addition,
                   the Transmission Provider undertakes no obligation
                   under this Tariff to plan its Transmission System so as
                   to have sufficient capacity for non-firm Transmission
                   Service.
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 21
         4.0   Service Availability
              4.1  General Conditions - Subject to the terms and
                   conditions of this Tariff, the Transmission Provider
                   will provide Firm and Non-firm Transmission Services
                   to, from, over and within the Transmission Provider's
                   Transmission System to any Transmission Customer that
                   has met the requirements of section 7.0 of this Tariff.
                   Nothing in this Tariff relieves or otherwise modifies
                   the obligation of a Transmission Customer or the
                   Transmission Provider from performing its obligations
                   under previously negotiated contractual commitments and
                   agreements.
              4.2  Determination of Capacity Availability - The
                   Transmission Provider will respond to a firm
                   Transmission Service request by performing studies,
                   when necessary, that assess whether sufficient transfer
                   capacity is available.  The amount of transfer capacity
                   available will be computed on a point-to-point basis in
                   the direction of the requested transfer.  The transfer
                   capacity available will be the remaining capacity after
                   taking into account the Transmission Provider's
                   reliability requirements to serve the projected demand
                   of Native Load Customers, Network Customers, existing
                   firm contracts and pending Valid Requests for firm
                   transmission under this Tariff.  The methodology and
                   the data used to develop the available transmission
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                                                     Original Sheet No. 22
                   capacity must be consistent with the information
                   submitted in the FERC Form No. 715, Annual Transmission
                   Planning and Evaluation Report.  A description of the
                   Transmission Provider's specific methodology for
                   assessing capacity availability is contained in
                   Appendix A, which is attached to and is part of this
                   Tariff.
              4.3  Initiating Service in the Absence of an Executed
                   Service Agreement - If the Transmission Provider and
                   the Transmission Customer requesting firm or non-firm
                   Transmission Service pursuant to this Tariff cannot
                   agree on all the terms and conditions of the Service
                   Agreement, the Transmission Provider shall file with
                   the Commission, within 10 days after the date the
                   Transmission Customer provides written notification
                   directing the Transmission Provider to file, an
                   unexecuted Service Agreement containing terms and
                   conditions deemed appropriate by the Transmission
                   Provider for such requested Transmission Service.  The
                   Transmission Provider shall commence providing
                   Transmission Service subject to the Transmission
                   Customer agreeing to: (i) compensate the Transmission
                   Provider at whatever rate the Commission ultimately
                   determines to be just and reasonable, and (ii) comply
                   with the terms of this Tariff including posting
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                                                     Original Sheet No. 23
                   appropriate security deposits in accordance with the
                   terms of Section 9.3 of this Tariff.
              4.4  Obligation to Expand or Modify Facilities - If the
                   Transmission Provider determines that it cannot
                   accommodate a Valid Request for firm Transmission
                   Service because of constraints on its Transmission
                   System, the Transmission Provider will use due
                   diligence to either redispatch its system or to add or
                   modify the necessary facilities required to provide the
                   requested firm Transmission Service, provided the
                   Transmission Customer agrees to compensate the
                   Transmission Provider for such costs pursuant to the
                   terms of Section 19 of this Tariff.  The Transmission
                   Provider will conform to Good Utility Practice in
                   determining the need for new facilities and in the
                   design and construction of such facilities and will
                   charge for such facilities in accordance with the
                   provisions of Section 19 of this Tariff.
              4.5  Other Transmission Service Schedules - Eligible
                   Customers receiving service under other transmission
                   service schedules filed with the Commission by the
                   Transmission Provider on or before [insert effective
                   date of this Tariff] may continue to receive service
                   under those schedules.  Such customers may obtain
                   service under this Tariff, if they fulfill all
                   obligations under the terms and conditions of their
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                                                     Original Sheet No. 24
                   currently effective service agreements and rate
                   schedules with the Transmission Provider.
         5.0   Real Time Information Network Requirements
              Terms and conditions regarding Real Time Information
         Networks or other comparable electronic bulletin boards will be
         set forth in FERC Order No.      (Final Order on Real Time
         Information Networks).
         6.0   Standards of Conduct
              In implementing the provisions of this Tariff, the Parties
         shall comply with the following standards of conduct:
              6.1  Standard of Nondiscrimination - In performing its
                   obligations under this Tariff, the Transmission
                   Provider shall apply the Tariff's provisions in a non-
                   discriminatory manner to all users, including the
                   Transmission Provider's use of this Tariff.
              6.2  Communications with Eligible Customers - The
                   Transmission Provider shall use all reasonable efforts
                   to communicate promptly with all Eligible Customers to
                   resolve any questions regarding their requests for
                   service and in a non-discriminatory manner.   
              6.3  Standard of Due Diligence - where the Transmission
                   Provider or the Transmission Customer is required to
                   complete activities or to negotiate agreements as a
                   condition of service under this Tariff, each party
                   shall use due diligence to complete these actions
                   within a reasonable time.    
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                                                     Original Sheet No. 25
              6.4  Dispute Resolution Procedures - If any Transmission
                   Customer has a dispute or complaint that relates to the
                   conduct of Transmission Provider under this Tariff, the
                   customer may use the dispute resolution procedures
                   provided in Section 25.
         7.0   Conditions Required of Transmission Customers
              Transmission Service shall be provided by the Transmission
         Provider under this Tariff only if the following conditions are
         satisfied by the Transmission Customer:
              a.   The Transmission Customer has pending a Valid Request
                   for service;
              b.   The Transmission Customer meets the creditworthiness
                   criteria set forth in Section 24 of this Tariff;
              c.   The Transmission Customer will have final arrangements
                   in place for any other transmission service necessary
                   to effect the delivery from the generating source to
                   the ultimate load prior to the time service under this
                   Tariff commences;
              d.   The Transmission Customer agrees to pay for any
                   facilities constructed and chargeable to such
                   Transmission Customer under this Tariff, whether or not
                   the Transmission Customer takes service for the full
                   term of its reservation;
              e.   A Transmission Customer receiving transmission service
                   under this Tariff agrees to provide comparable service
                   to the Transmission Provider on similar terms and
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                                                     Original Sheet No. 26
                   conditions over transmission facilities owned or
                   controlled, or which will be owned or controlled by the
                   Transmission Customer and its affiliates.  A
                   Transmission Customer that has on file with the
                   Commission transmission tariffs of general
                   applicability that meet the Commission's comparability
                   of service standard shall be deemed to meet this
                   reciprocity requirement; and
              f.   The Transmission Customer has executed a Service
                   Agreement or is receiving service pursuant to Section
                   4.3 of this Tariff.
         8.0   Ancillary Services
              Ancillary services include all services necessary to support
         the transmission of electric power from resources to load while
         maintaining reliable operation of the Transmission Provider's
         Transmission System.  A  Transmission Customer may purchase the
         ancillary services necessary for prudent utility operation from
         the Transmission Provider or from another supplier where the
         purchase is consistent with Good Utility Practice and is
         technically feasible.  To the extent that the Transmission
         Provider provides itself with any ancillary services, or the
         Transmission Provider is capable of providing itself with any
         ancillary services, the Transmission Provider will be required to
         offer to the Transmission Customer similar ancillary services
         pursuant to Good Utility Practice.  The specific ancillary
         services, prices and/or compensation methods are described on the
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                                                     Original Sheet No. 27
         Schedules that are attached to and made a part of this Tariff.
         Sections 8.1 through 8.6, below list examples of possible
         ancillary services.  The Transmission Provider shall list all of
         the Ancillary Services it is capable of providing and appropriate
         Schedules for such services.
              8.1  Loss Compensation Service - Where applicable the rates
                   and/or methodology are described in Schedule 1.
              8.2  Load Following Service - Where applicable the rates
                   and/or methodology are described in Schedule 2.
              8.3  System Protection Service - Where applicable the rates
                   and/or methodology are described in Schedule 3.
              8.4  Energy Imbalance Service - Where applicable the rates
                   and/or methodology are described in Schedule 4.
              8.5  Reactive Power/Voltage Control Service - Where
                   applicable the rates and/or methodology are described
                   in Schedule 5.
              8.6  Scheduling and Dispatching Service - Where applicable
                   the rates and/or methodology are described in
                   Schedule 6.
         9.0   Procedures for Arranging Firm Service
              9.1  Application - A request for firm Transmission Service
                   under this Tariff for periods of one year or longer
                   must contain a written Application to:  [Transmission
                   Provider Name and Address], at least sixty (60) days in
                   advance of the calendar month in which service is to
                   commence.  The Transmission Provider will consider
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                                                     Original Sheet No. 28
                   requests for such firm service on shorter notice when
                   feasible.  Requests for firm service for periods of
                   less than one year shall be subject to expedited
                   procedures that shall be negotiated between the parties
                   within the time constraints provided in Section 9.5.
                   Such short-term firm transmission requests may be
                   submitted by (i) entering the information listed below
                   directly on the Transmission Provider's Real Time
                   Information Network, (ii) transmitting the required
                   information to the Transmission Provider by telefax, or
                   (iii) providing the information by telephone over the
                   Transmission Provider's time recorded telephone line.
                   Each of these methods will provide a time-stamped
                   record for establishing the priority of the
                   Application.
              9.2  Completed Application - A completed Application shall
                   provide all of the information included in 18 CFR §
                   2.20 including but not limited to the following:
                   (i)  The identity, address and telephone number of the
                        entity requesting service.
                   (ii) A statement that the entity requesting service is,
                        or will be upon commencement of service, an
                        Eligible Customer under this Tariff.
                  (iii) The location of the Point(s) of Receipt
                        and Point(s) of Delivery and the identities of the
                        Delivering Parties and the Receiving Parties
                   (iv) The location of the generating facility(ies)
                        supplying the capacity and energy and the location
                        of the load ultimately served by the capacity and
                        energy transmitted.  The Transmission Provider
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                        will treat this information as confidential except
                        to the extent that disclosure of this information
                        is required by this tariff, by regulatory or
                        judicial order, for reliability purposes pursuant
                        to Good Utility Practice or pursuant to RTG
                        transmission information sharing agreements.  The
                        Transmission Provider shall not disclose this
                        information to its marketing personnel.
                 (v)    A description of the supply characteristics of the
                        capacity and energy to be delivered.
                 (vi)   An estimate of the capacity and energy expected to
                        be delivered to the Receiving Party.
                 (vii)  The Service Commencement Date and the term of the
                        requested Transmission Service.
                 (viii) The transmission capacity requirement for
                        each Point of Receipt (1,000 kilowatt minimum) and
                        each Point of Delivery (no minimum) on the
                        Transmission Provider's Transmission System;
                        customers may combine their requests for service
                        in order to satisfy the minimum transmission
                        capacity requirement.  
              9.3  Deposit - A Completed Application for firm Transmission
                   Service also shall include a deposit of either one
                   month's charge for Reserved Capacity or the full charge
                   for Reserved Capacity for service requests of less than
                   one month.  If the Application is rejected by the
                   Transmission Provider because it does not meet the
                   conditions for service as set forth herein, or in the
                   case of requests for service arising in connection with
                   losing bidders in a request for proposals ("RFP"), said
                   deposit shall be returned with interest.  The one-month
                   reservation charge deposit also will be returned with
                   interest if the Transmission Provider is unable to
                   complete new facilities needed to provide the service.
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                   If an Application is withdrawn or the Transmission
                   Customer decides not to enter into a Service Agreement,
                   the reservation charge deposit shall be refunded in
                   full, with interest, less reasonable costs incurred by
                   the Transmission Provider for a System Impact Study to
                   the extent such costs have not already been recovered
                   by the Transmission Provider from the Transmission
                   Customer.  The Transmission Provider will provide to
                   the Transmission Customer a complete accounting of all
                   costs deducted from the refunded reservation charge
                   deposit, which the Transmission Customer may contest if
                   there is a dispute concerning the deducted costs.
                   Deposits associated with construction of new facilities
                   are subject to the provisions of Section 11.  If a
                   Service Agreement is executed, the deposit, with
                   interest, will be credited against the Transmission
                   Customer's obligations under the Tariff.  Any amount
                   remaining will be returned to the Transmission Customer
                   upon expiration of the Service Agreement.  Applicable
                   interest shall be computed in accordance with the
                   Commission's regulations at 18 CFR § 35.19a(a)(2)(iii),
                   and shall be calculated from the day the deposit check
                   is credited to the Transmission Provider's account.
              9.4  Notice of Deficient Application - If an Application
                   fails to meet the requirements of this Tariff, the
                   Transmission Provider shall notify the entity
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                   requesting service within fifteen (15) days of receipt
                   of the reasons for such failure.  The Transmission
                   Provider will attempt to remedy minor deficiencies in
                   the Application through informal communications with
                   the Transmission Customer.  If such efforts are
                   unsuccessful, the Transmission Provider shall return
                   the Application, along with any deposit, with interest.
                   Upon receipt of a new or revised Application that fully
                   complies with the requirements of this Tariff, the
                   Transmission Customer shall be assigned a new priority
                   consistent with the date of the new or revised
                   Application.
              9.5  Response to Valid Requests - Following receipt of a
                   Completed Application for firm transmission service,
                   the Transmission Provider shall make a determination of
                   capacity availability as required in Section 11 of this
                   Tariff.  The Transmission Provider shall notify the
                   Transmission Customer as soon as practicable, but not
                   later than thirty (30) days after the date of receipt
                   of a Completed Application either (i) if it will be
                   able to provide service under this Tariff without
                   performing a System Impact Study or (ii) if such a
                   study is needed to evaluate the impact of the
                   Application.  
              9.6  Tendering of Service Agreement - Whenever the
                   Transmission Provider determines that a System Impact
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                   Study is not required and that the service can be
                   provided, it shall notify the Transmission Customer in
                   writing and tender a Service Agreement within thirty
                   (30) days of receipt of the Completed Application.
                   Where a System Impact Study is required, the provisions
                   of Section 11 of this Tariff will govern the tendering
                   and execution of a Service Agreement between the
                   Transmission Provider and a Transmission Customer.
                   Failure of a Transmission Customer to execute and
                   return such Service Agreement or request the filing of
                   an unexecuted service agreement pursuant to section
                   4.3, within thirty (30) days after it is tendered by
                   the Transmission Provider will be deemed a withdrawal
                   and termination of the Application and any deposit
                   submitted shall be refunded with interest.  Nothing
                   herein limits the right of a Transmission Customer to
                   file another Application after such withdrawal and
                   termination.
              9.7  Extensions for Commencement of Service - A Transmission
                   Customer can obtain up to five (5) yearly extensions or
                   a reasonable extension period for the Commencement of
                   Service.  A Transmission Customer may postpone service
                   by paying a non-refundable annual reservation fee equal
                   to one-month's charge for Firm Transmission Service for
                   each year or fraction thereof.  If during any extension
                   for the Commencement of Service another Transmission
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                   Customer submits a Completed Request for firm
                   Transmission Service, and such request can be satisfied
                   out of existing capacity only by releasing the capacity
                   reserved by the Transmission Customer, the request for
                   Service submitted by the original Transmission Customer
                   shall cease to be a Valid Request unless, within 30
                   days, the original Transmission Customer agrees to pay
                   the full monthly reservation fee for Firm Transmission
                   Service pursuant to this Tariff concurrent with the
                   Service Commencement Date specified in the new
                   Completed Request.  In the event the Transmission
                   Customer elects to release the reserved transmission
                   capacity, the reservation fees paid will be forfeited.
              9.8  Termination of Service -  A Transmission Customer may
                   terminate firm service under this Tariff no earlier
                   than 2 years or a reasonable time that is generally
                   accepted in the region and is consistently adhered to
                   by the Transmission Provider after providing the
                   Transmission Provider with written notice of the
                   Transmission Customer's intention to terminate.  A
                   Transmission Customer wishing to terminate service
                   prior to the expiration of the term specified in the
                   Service Agreement will be responsible for all charges
                   related to the construction of facilities, specified
                   under the applicable Service Agreement and which are
                   owed to the Transmission Provider as of the date of
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                   termination unless reassigned consistent with the
                   reassignment provision of this tariff.
         10.0  Procedures for Arranging Non-Firm Transmission Service  
            10.1   Application - Eligible Customers seeking non-firm
                   service under this Tariff must submit a Completed
                   Application to the Transmission Provider (to the same
                   address specified in Section 9.1).  Applications may be
                   submitted by (i) entering the information listed below
                   directly on the Transmission Provider's Real Time
                   Information Network, (ii) transmitting the required
                   information to the Transmission Provider by telefax, or
                   (iii) providing the information by telephone over the
                   Transmission Provider's time recorded telephone line.
                   Each of these methods will provide a time-stamped
                   record for establishing the service priority of the
                   Application.
            10.2   Completed Application - A completed Application shall
                   provide all of the information included in 18 CFR §
                   2.20 including but not limited to the following:
                   (i)  the identity, address and telephone number of the
                        entity requesting service;
                 (ii)   a statement that the entity requesting service is,
                        or will be upon commencement of service, an
                        Eligible Customer under this Tariff;  
                 (iii)  the Point(s) of Receipt and the Point(s) of
                        Delivery;
                 (iv)   the maximum amount of capacity requested at each
                        Point of Receipt and Point of Delivery; and
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                 (v)    the proposed dates and hours for initiating and
                        terminating transmission service hereunder.  
                   In addition to the information specified above, when
                   required to properly evaluate system conditions, the
                   Transmission Provider also may ask the Transmission
                   Customer to provide the following:
                 (vi)   the electrical location of the initial source of
                        the power to be transmitted pursuant to the
                        Transmission Customer's request for service;
                 (vii)  the electrical location of the ultimate load.
                   The Transmission Provider will treat this information
                   in (vi) and (vii) as confidential at the request of the
                   Transmission Customer except to the extent that
                   disclosure of this information is required by this
                   tariff, by regulatory or judicial order, for
                   reliability purposes pursuant to Good Utility Practice,
                   or pursuant to RTG transmission information sharing
                   agreements.  The Transmission Provider shall not
                   disclose confidential information to its marketing
                   personnel.
            10.3   Reservation of Non-Firm Transmission Service - Requests
                   to reserve monthly service shall be submitted no
                   earlier than 60 days before service is to commence;
                   requests to reserve weekly service shall be submitted
                   no earlier than 14 days before service is to commence,
                   requests to reserve daily service shall be submitted no
                   earlier than 2 days before service is to commence, and
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                   requests to reserve hourly service shall be submitted
                   no earlier than noon the day before service is to
                   commence.  Requests for service must be received no
                   later than 2:00 p.m. prior to the day service is
                   scheduled to commence or such reasonable times that are
                   generally accepted in the region and are consistently
                   adhered to by the Transmission Provider.
             10.4  Determination of Capacity Availability - Following
                   receipt of a tendered schedule the Transmission
                   Provider will make a determination on a
                   nondiscriminatory basis of capacity availability.  Such
                   determination shall be made as soon as reasonably
                   practicable after receipt, but not later than the
                   following time periods for the following terms of
                   service (i) thirty minutes for hourly service, (ii)
                   thirty minutes for daily service, (iii) four hours for
                   weekly service, and (iv) two days for monthly service.
                   Or such reasonable times that are generally accepted in
                   the region and are consistently adhered to by the
                   Transmission Provider.
            10.5   Charges For Schedule Changes - For a given transaction,
                   the Transmission Customer may make up to six schedule
                   changes per day at no additional charge.  Any
                   additional changes may be made at a charge of $ 25 per
                   additional schedule change, or a reasonable number of
                   schedule changes and additional charges that are
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                   generally accepted in the region and are consistently
                   adhered to by the Transmission Provider.  
            10.6   Transmission Customer Responsibility for Third-Party
                   Arrangements - Any scheduling arrangements that may be
                   required by other electric systems shall be the
                   responsibility of the Transmission Customer requesting
                   service.  The Transmission Customer shall provide,
                   unless waived by the Transmission Provider,
                   notification to the Transmission Provider identifying
                   such systems and authorizing them to schedule the
                   energy to be transmitted by the Transmission Provider
                   pursuant to the Service Agreement on behalf of the
                   Receiving Party at the Point of Delivery or the
                   Delivering Party at the Point of Receipt.  However, the
                   Transmission Provider will undertake reasonable efforts
                   to assist the Transmission Customer in making such
                   arrangements, including without limitation, providing
                   any information or data required by such other electric
                   system pursuant to Good Utility Practice.
         11.0  Determination of Capacity Availability and Responsibility   
               for Costs Incurred in Providing Firm Transmission Service
            11.1   Notice of Need for System Impact Study - After
                   receiving a request for service, the Transmission
                   Provider shall determine on a nondiscriminatory basis
                   whether a System Impact Study is needed in the same
                   manner that it would determine if a System Impact Study
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                   is needed for providing service to itself.  If the
                   Transmission Provider determines that the Transmission
                   System will be inadequate to accommodate a request for
                   service or that either redispatching of its system, or
                   alternatively, construction of Direct Assignment
                   Facilities or Network Upgrades could be required to
                   provide the requested service, it shall so inform the
                   Applicant, within thirty (30) days of receipt of a
                   Completed Application.  In such cases, the Transmission
                   Provider shall tender an agreement (the "Study
                   Agreement") pursuant to which the Transmission Customer
                   shall agree to reimburse the Transmission Provider for
                   performing the required System Impact Study.  A
                   description of the Transmission Provider's methodology
                   for completing a System Impact Study is provided in
                   Appendix D.  
            11.2   Study Agreement and Cost Reimbursement -  
                   (i)  The Study Agreement will clearly specify the
                        maximum charge, based on the Transmission
                        Provider's estimate of the actual cost, and time
                        for completion of the System Impact Study.  The
                        charge shall not exceed the actual cost of the
                        study.  The study shall identify any system
                        constraints and redispatch options, additional
                        system or Direct Assignment Facilities or Network
                        Upgrades required to provide the requested
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                        service, the total projected cost and estimated
                        time to complete the additional facilities or
                        upgrades, and the portion of such costs to be
                        charged to the Transmission Customer pursuant to
                        Section 19 of this Tariff.  A description of the
                        methodology that will be used by the Transmission
                        Provider in assessing capacity available to
                        provide service is contained in Appendix A to this
                        Tariff.  The criteria specified in Appendix A are
                        provided to apprise the Transmission Customer of
                        the criteria the Transmission Provider intends to
                        apply, but shall not be deemed to bind the
                        Commission in reviewing any dispute over the
                        availability of capacity to provide Firm
                        Transmission Service.  In performing the System
                        Impact Study, the Transmission Provider shall
                        rely, to the extent reasonably practicable, on
                        existing transmission planning studies.  The
                        Transmission Customer will not be assessed a
                        charge for such existing studies; however, the
                        Transmission Customer will be responsible for
                        charges associated with any modifications to
                        existing planning studies that are reasonably
                        necessary in evaluating the impact of the
                        Transmission Customer's request for service on the
                        Transmission System.  
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                   (ii) In cases where a single System Impact Study is
                        sufficient for the Transmission Provider to assess
                        capacity availability, in response to multiple
                        Eligible Customers requesting service in relation
                        to the same competitive solicitation, the costs of
                        that study shall be prorated among the Eligible
                        Customers.
                  (iii) For a service request to remain a Valid Request,
                        the Transmission Customer shall execute the Study
                        Agreement and return it to the Transmission
                        Provider within thirty (30) days.  If the
                        Transmission Customer elects not to execute the
                        Study Agreement, its application shall be deemed
                        withdrawn and its deposit, pursuant to Section
                        9.3, shall be returned with interest.
                   (iv) For studies that the Transmission Provider
                        conducts on its own behalf, the Transmission
                        Provider shall book the costs of the studies into
                        a separate revenue account.
            11.3   Performance of System Impact Study - Upon receipt of an
                   executed Study Agreement, the Transmission Provider
                   will use due diligence to complete the required System
                   Impact Study within a sixty (60) day period.  In the
                   event that the Transmission Provider is unable to
                   complete the required studies within such time period,
                   it shall so notify the Transmission Customer and
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                   provide an estimated completion date along with an
                   explanation of the reasons why additional time is
                   required to complete the required studies.  A copy of
                   the completed study and related work papers shall be
                   made available to the Transmission Customer.  The
                   Transmission Provider will use the same due diligence
                   in completing the studies for a Transmission Customer
                   as it uses when completing studies for itself.
            11.4   Initial Allocation of Available Capacity - For purposes
                   of determining whether existing capacity on the
                   Transmission Provider's Transmission System is adequate
                   to accommodate a request for firm Transmission Service,
                   all completed Applications received during the initial
                   sixty (60) day period commencing with the effective
                   date of this Tariff will be deemed to have been filed
                   simultaneously.  A lottery system conducted by an
                   independent party shall be used to assign priorities
                   for Completed Applications filed simultaneously.  All
                   Completed Applications received after the initial sixty
                   (60) day period shall be assigned a priority on a
                   first-come, first-served basis according to the date
                   and time of receipt.  
            11.5   Determining Need for New Facilities - The Transmission
                   Provider may defer providing service until it completes
                   construction of new transmission facilities or upgrades
                   needed to provide firm Transmission Service whenever
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                   the Transmission Provider determines that providing the
                   requested Service would, without such new facilities or
                   upgrades, impair or degrade reliability of service to
                   Native Load and Network Integration Transmission
                   Customers, or interfere with service under pre-existing
                   firm contractual arrangements.  The costs of any new
                   facilities to be charged to the Transmission Customer
                   under this Tariff will be specified in the Service
                   Agreement prior to initiating service.
            11.6   Tendering of Service Agreement in the Absence of Need
                   for New Facilities - If the System Impact Study
                   undertaken by the Transmission Provider concludes that
                   the Transmission System will be adequate to accommodate
                   a request, or a partial request, for service or that no
                   costs are likely to be incurred for new transmission
                   facilities or upgrades, within 15 days of completion of
                   the System Impact Study, the Transmission Provider
                   shall tender a Service Agreement to the Transmission
                   Customer.  In order for a request to remain a Valid
                   Request, within thirty (30) days of the receipt of the
                   Service Agreement the Transmission Customer must
                   execute such Agreement or request the filing of an
                   unexecuted service agreement pursuant to Section 4.3,
                   or the Application shall be deemed terminated and
                   withdrawn.  If the Application is withdrawn, the
                   Transmission Provider shall refund the Transmission
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                   Customer's deposit, with interest, minus any unpaid
                   study costs.
            11.7   Tendering of Facilities Study Agreement Where
                   Construction of New Facilities is Contemplated - If the
                   Transmission Provider determines that additions or
                   upgrades to the Transmission System are needed to
                   supply the Transmission Customer's forecasted
                   transmission requirements, within thirty (30) days of
                   the completion of the System Impact Study the
                   Transmission Provider shall tender to the Transmission
                   Customer a Facilities Study Agreement.  If additional
                   time is required, the Transmission Provider shall
                   notify the Transmission Customer on a timely basis and
                   provide an estimate of the time needed to reach a final
                   determination along with an explanation of the reasons
                   why additional time is required to complete the study.
                   When completed, the Facilities Study will include a
                   binding estimate of:  (i) the cost of Direct Assignment
                   Facilities to be charged to the Transmission Customer,
                   (ii) the Transmission Customer's appropriate share of
                   the cost of any required Network Upgrades as determined
                   pursuant to the provisions of the Tariff; and (iii) the
                   time required to complete such construction and
                   initiate the requested service.  In order for a request
                   to remain a Valid Request, within thirty (30) days of
                   the receipt of the Facilities Study Agreement the
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                   Transmission Customer shall execute such Agreement or
                   the request shall be deemed terminated and withdrawn.
                   If the request is withdrawn, the Transmission Provider
                   shall refund the Transmission Customer's deposit, with
                   interest, minus any unpaid study costs.
            11.8   Due Diligence in Completing New Facilities - The
                   Transmission Provider shall use due diligence to add
                   necessary facilities or upgrade its Transmission System
                   within a reasonable time.  The Transmission Provider
                   will not upgrade the capacity of its existing or
                   planned Transmission System in order to provide the
                   requested firm Transmission Service if doing so would
                   impair system reliability or otherwise impair or
                   degrade firm service to the Transmission Provider's
                   Native Load Customers, its obligations to its network
                   customers under the Network Integration Service Tariff
                   or its firm transmission service customers under the
                   Point-To-Point Transmission Tariff.
            11.9   Partial Interim Service - If the Transmission Provider
                   determines that it will not have adequate transmission
                   capacity to satisfy the full amount of a Valid Request
                   for firm Transmission Service, the Transmission
                   Provider nonetheless shall be obligated to offer and
                   provide the portion of the requested firm Transmission
                   Service that can be accommodated without addition of
                   any facilities and through redispatch.  However, the
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                   Transmission Provider shall not be obligated to provide
                   the incremental amount of requested firm Transmission
                   Service that requires the addition of facilities or
                   upgrades to the Transmission System until such
                   facilities or upgrades have been placed in service.
            11.10  Facilities Study Modifications - Any change in design
                   arising from inability to site or construct facilities
                   as proposed will require development of a new binding
                   cost estimate.  New binding cost estimates also will be
                   required in the event of new statutory or regulatory
                   requirements that are effective before the completion
                   of construction or other circumstances beyond the
                   control of the Transmission Provider that affect the
                   final cost of new facilities or upgrades to be charged
                   to the Transmission Customer pursuant to the provisions
                   of the Tariff.  The Transmission Customer also shall
                   provide the Transmission Provider with a letter of
                   credit or other reasonable form of security acceptable
                   to the Transmission Provider equivalent to the costs of
                   new facilities or upgrades consistent with commercial
                   practices as established by the Uniform Commercial
                   Code.  The Transmission Customer shall have thirty (30)
                   days to provide the required letter of credit or other
                   form of security or the request no longer will be a
                   Valid Request and shall be deemed terminated and
                   withdrawn and the Transmission Provider shall refund
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                                                     Original Sheet No. 46
                   the Transmission Customer's deposit, with interest,
                   minus any unpaid study costs.
            11.11  Expedited Procedures for New Facilities - In lieu of
                   the procedures set forth above, a Transmission Customer
                   shall have the option to expedite the process by
                   requesting the Transmission Provider to tender at one
                   time, together with the results of required studies, an
                   "Expedited Service Agreement" pursuant to which the
                   Transmission Customer would agree to compensate the
                   Transmission Provider for all costs incurred pursuant
                   to the terms of this Tariff.  In order to exercise this
                   option, the Transmission Customer shall request in
                   writing an expedited Service Agreement covering all of
                   the above-specified items within thirty (30) days of
                   receiving the results of the System Impact Study
                   identifying needed facility additions or upgrades or
                   costs incurred in providing the requested service.
                   While the Transmission Provider agrees to provide the
                   Transmission Customer with its best estimate of the new
                   facility costs and other charges that may be incurred,
                   such estimate shall not be binding and the Transmission
                   Customer must agree in writing to compensate the
                   Transmission Provider for all costs incurred pursuant
                   to the provisions of this Tariff.  The Transmission
                   Customer shall execute such an Expedited Service
                   Agreement within thirty (30) days of its receipt or the
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                                                     Original Sheet No. 47
                   Transmission Customer's request for service will cease
                   to be a Valid Request and will be deemed terminated and
                   withdrawn.
         12.0  Procedures if The Transmission Provider is Unable to
               Complete New Transmission Facilities for Firm Transmission
               Service  
            12.1   Delays or Constraints in Construction of New Facilities
                   If any event occurs that will materially affect the
                   time for completion of new facilities, or the ability
                   to complete them, the Transmission Provider shall
                   promptly notify the Transmission Customer.  In such
                   circumstances, the Transmission Provider shall within
                   thirty (30) days of notifying the Transmission Customer
                   of such constraints convene a technical meeting with
                   the Transmission Customer to evaluate the alternatives
                   available to the Transmission Customer.  The
                   Transmission Provider also shall make available to the
                   Transmission Customer studies and work papers,
                   including all information that is in the possession of
                   the Transmission Provider that is reasonably needed by
                   the Transmission Customer to evaluate any alternatives.
            12.2   Alternatives to Constrained Facility Additions - When
                   the review process of section 12.1 above determines
                   that one or more alternatives exist to the originally
                   planned construction project, the Transmission Provider
                   shall present such alternatives for consideration by
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                   the Transmission Customer.  If, upon such presentation
                   of alternatives by the Transmission Provider, the
                   Transmission Customer desires to maintain the Service
                   Agreement in effect subject to such alternatives, it
                   may request the Transmission Provider to perform
                   supplemental System Impact Studies pursuant to Section
                   11 of this Tariff and to submit a revised Service
                   Agreement; provided that if the alternative approach
                   solely involves a lesser quantity of firm Transmission
                   Service or non-firm Transmission Service, and if no
                   system impact studies are necessary, the Transmission
                   Provider shall promptly tender a Service Agreement
                   providing for the service.  In the event the
                   Transmission Provider concludes that no reasonable
                   alternative exists and the Transmission Customer
                   disagrees, the Transmission Customer may seek relief
                   under the dispute resolution procedures under Section
                   25.  
            12.3   Refund Obligation for Constrained Facility Additions -
                   If the Transmission Provider and the Transmission
                   Customer mutually agree that no other reasonable
                   alternatives exist and the requested service cannot be
                   provided out of existing capacity under the conditions
                   of this Tariff, the obligation to provide the requested
                   firm Transmission Service pursuant to this Tariff shall
                   terminate and any deposit made by the Transmission
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                                                     Original Sheet No. 49
                   Customer shall be returned with interest pursuant to
                   Commission Regulations 35.19a(a) (2) (iii).  However,
                   the Transmission Customer shall be responsible for all
                   prudent costs incurred by the Transmission Provider
                   through the time construction was suspended.
         13.0  Provisions Relating to Transmission Construction and        
               Services on the Systems of Other Utilities
            13.1   Responsibility for Third-Party System Additions - The
                   Transmission Provider shall not be responsible for
                   making arrangements for any necessary engineering,
                   permitting, and construction of transmission or
                   distribution facilities on the system(s) of any other
                   entity or for obtaining any regulatory approval for
                   such facilities.  The Transmission Provider will
                   undertake reasonable efforts to assist the Transmission
                   Customer in obtaining such arrangements, including
                   without limitation, providing any information or data
                   required by such other electric system pursuant to Good
                   Utility Practice.
            13.2   Coordination of Third-Party System Additions - In
                   circumstances where the need for transmission
                   facilities or upgrades is identified pursuant to the
                   provisions of this Tariff, and if such upgrades further
                   require the addition of transmission facilities on
                   other systems, the Transmission Provider shall have the
                   right to coordinate construction on its own system with
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                                                     Original Sheet No. 50
                   the construction required by others.  The Transmission
                   Provider, after consultation with the Transmission
                   Customer and representatives of such other systems, may
                   defer construction of new transmission facilities on
                   its own system pending the resolution of obstacles to
                   the timely completion of new transmission facilities on
                   other systems that would be needed to provide the
                   requested service.  The Transmission Provider shall
                   notify the Transmission Customer in writing of the
                   basis for its deferral decision and the specific
                   obstacles which must be resolved before it will
                   initiate or resume construction of new facilities.
                   Within 60 days of receiving written notification by the
                   Transmission Provider of its intent to defer
                   construction pursuant to this paragraph, the
                   Transmission Customer may challenge such a deferral
                   decision in accordance with the dispute resolution
                   procedures of this Tariff or it may refer the dispute
                   to the Commission for  resolution.
         14.0  Changes in Service Specifications
            14.1   Modifications On a Non-Firm Basis - A Transmission
                   Customer of Firm Transmission Service may request the
                   Transmission Provider to provide non-firm Transmission
                   Service over Receipt and Delivery Points other than
                   those specified in the Service Agreement ("Secondary
                   Receipt and Delivery Points"), in amounts not to exceed
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                                                     Original Sheet No. 51
                   its firm capacity reservation, without incurring any
                   additional reservation charges or executing a new
                   Service Agreement, subject to the following conditions.
                   (a)  Service provided over Secondary Receipt and
                        Delivery Points will be non-firm only, on a
                        capacity-available basis and will not displace any
                        firm or non-firm service previously scheduled by
                        third-parties under this Tariff or under the
                        Network Integration Tariff or by the Transmission
                        Provider on behalf of its Native Load Customers.
                   (b)  The sum of all firm and non-firm Transmission
                        Service provided to the Transmission Customer at
                        any time shall not exceed the capacity reservation
                        in the relevant Service Agreement under which such
                        services are provided.
                   (c)  The Transmission Customer shall retain its right
                        to schedule Firm Transmission Service at the
                        Receipt and Delivery Points specified in the
                        relevant Service Agreement in the amount of its
                        original capacity reservation.
                   (d)  Service over Secondary Receipt and Delivery Points
                        on a non-firm basis shall not require the filing
                        of an Application for Non-Firm Transmission
                        Service under this Tariff.  However, all other
                        requirements of the Tariff (except as to
                        transmission rates) shall apply to non-firm
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                        service over Secondary Receipt and Delivery
                        Points.
            14.2   Modification On a Firm Basis - Any request by a
                   Transmission Customer to modify Receipt and/or Delivery
                   Points on a firm basis shall be treated as a new
                   request for service in accordance with Section 9
                   hereof, except that such Transmission Customer shall
                   not be obligated to pay any additional deposit or
                   reservation fee if the capacity reservation does not
                   exceed the amount reserved in the existing Service
                   Agreement.  While such new request is pending, the
                   Transmission Customer shall retain its priority for
                   service at the existing firm Points of Receipt and
                   Delivery.
         15.0  Sale or Assignment of Transmission Service
            15.1   Procedures for Assignment or Transfer of Service -
                   Subject to Commission approval of any necessary
                   filings, a Transmission Customer may sell, assign, or
                   transfer all or a portion of its rights under its
                   Service Agreement, but only to another Eligible
                   Customer (the "Assignee").  Any sale, assignment or
                   transfer shall not result in the Transmission Customer
                   receiving compensation that exceeds the rate  by the
                   Transmission Provider for similar service.  If the
                   Assignee does not request any change in the Point(s) of
                   Receipt or the Point(s) of Delivery, or a change in any
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                   other term or condition set forth in the original
                   Service Agreement, the Assignee will receive the same
                   services as did the first Transmission Customer and the
                   priority of service for the Assignee will be the same
                   as that of the original Transmission Customer.  If the
                   Assignee requests a change in service, the priority of
                   service will be determined by the Transmission Provider
                   based on the date the Transmission Provider receives
                   notice of the proposed assignment.  Such notice must
                   contain all the information required by Section 9 of
                   this Tariff.
            15.2   Limitations on Assignment or Transfer of Service - If
                   the Assignee requests a change in the Point(s) of
                   Receipt or Point(s) of Delivery, or a change in any
                   other term or condition set forth in the original
                   Service Agreement, the Transmission Provider will
                   consent to such change subject to the provisions of
                   this Tariff, but only if to do so will not impair the
                   operation and reliability of the Transmission
                   Provider's generation, transmission, or distribution
                   systems, and on the condition that the Assignee agrees
                   to compensate the Transmission Provider for performing
                   any System Impact Study needed to evaluate the capacity
                   of the Transmission System to accommodate the proposed
                   change and any additional costs resulting from such
                   change.  The original Transmission Customer shall
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                                                     Original Sheet No. 54
                   remain liable for the performance of all obligations
                   under the Service Agreement, except as specifically
                   agreed to by the Parties through an amendment to the
                   Service Agreement.
            15.3   Information on Assignment or Transfer of Service  - In
                   accordance with Section 5.0, Transmission Customers or
                   Assignees may use the Transmission Provider's Real Time
                   Information Network to post capacity availability.
                   Postings on the Real Time Information Network will be
                   set forth in FERC Order No.      (Final Order on Real
                   Time Information Network).  
         16.0  Metering and Power Factor Correction
            16.1   Transmission Customer Obligations - Unless otherwise
                   agreed, the Transmission Customer shall be responsible
                   for installing and maintaining compatible metering and
                   communications equipment to accurately account for the
                   generating capacity and associated energy being
                   transmitted under this Tariff and to communicate the
                   information to the appropriate Transmission Provider
                   facility.  Such equipment shall remain the property of
                   the Transmission Customer and shall meet the applicable
                   requirements of the Service Agreement.
            16.2   Transmission Provider Access to Metering Data - The
                   Transmission Provider shall have access to metering
                   data, which may reasonably be required to facilitate
                   measurements and billing under the Service Agreement.
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            16.3   Power Factor - The Transmission Customer is required to
                   maintain a power factor within the same range as the
                   Transmission Provider pursuant to Good Utility
                   Practices.  
         17.0  Compensation for Transmission Service
              Rates for firm and non-firm Transmission Service are
         provided in the Rate Schedules appended to this Tariff:  Firm
         Transmission Service (Schedule FTS); Short Term Non-firm Service
         (Schedule STNF); and Hourly Non-firm Service (Schedule HNF).  The
         Transmission Provider will apply the same rates to the
         transmission service it provides itself under this Tariff.  The
         Transmission Provider shall book revenues for all transmission
         service it provides itself under this Tariff pursuant to Section
         20 of this Tariff.   
         18.0  Other Charges
            18.1   Stranded Cost Recovery - The Transmission Provider may
                   seek to recover stranded costs from a Transmission
                   Customer pursuant to this Transmission Tariff in
                   accordance with the terms, conditions and procedures
                   set forth in FERC Order No.      (Final Order on Open
                   Access and Stranded Costs).  However, the Transmission
                   Provider must separately file any specific proposed
                   stranded cost charge under section 205 of the Federal
                   Power Act.
            18.2   Termination Charge - The term of service will be set
                   forth in the Service Agreement.  A firm Transmission
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                   Customer wishing to terminate service prior to the
                   expiration of the term will be responsible for
                   providing written notice pursuant to Section 9.8 of
                   this Tariff.
         19.0  Compensation for New Facilities and Redispatch Costs
              Whenever System Impact Studies performed by the Transmission
         Provider in connection with the provision of firm Transmission
         Service, identify the need for new facilities, the Transmission
         Customer shall be responsible for such costs to the extent
         consistent with Commission policy.  Whenever System Impact
         Studies performed by the Transmission Provider identify capacity
         constraints that may be relieved more economically through
         redispatching the system rather than by building new facilities
         or upgrading existing facilities to eliminate such constraints,
         the Transmission Customer shall be responsible for such costs to
         the extent consistent with Commission policy.
         20.0  Booking of Revenues Attributable to The Transmission        
               Provider's Use of this Tariff.
              To ensure transmission pricing comparability with respect to
         access to power markets, the Transmission Provider shall charge
         itself and book into separate revenue accounts, as outlined
         below, the following amounts:
                   (a)  Transmission Revenues - the revenues it receives
                        from transmission service that it provides itself
                        for off-system and third-party sales under this
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                                                     Original Sheet No. 57
                        Tariff, based on the rates specified in this
                        Tariff;
                   (b)  Impact Study Costs -  the cost to perform any
                        System Impact Studies or Facilities Studies that
                        the Transmission Provider undertakes to determine
                        if the Transmission Provider must construct new
                        transmission facilities or upgrades necessary for
                        the Transmission Provider to provide new
                        transmission service for itself under this Tariff;
         21.0  Billing and Payment
            21.1   Billing Procedure - Within a reasonable time after the
                   first day of each month, the Transmission Provider
                   shall submit an invoice to the Transmission Customer
                   for the charges for all transmission services furnished
                   during the preceding month.  The invoice shall be paid
                   by the Transmission Customer within 20 days of receipt.
                   All payments shall be made in immediately available
                   funds payable to the Transmission Provider [Name and
                   Address], or by wire transfer to a bank named by the
                   Transmission Provider.   
            21.2   Interest on Unpaid Balances - Interest on any unpaid
                   amount shall be calculated in accordance with the
                   methodology specified for interest on refunds in the
                   Commission's regulations at 18 C.F.R. §
                   35.19a(a)(2)(iii).  Interest on delinquent amounts
                   shall be calculated from the due date of the bill to
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                                                     Original Sheet No. 58
                   the date of payment.  When payments are made by mail,
                   bills shall be considered as having been paid on the
                   date of receipt by the Transmission Provider.
            21.3   Customer Default - In the event the Transmission
                   Customer fails, for any reason other than a billing
                   dispute as described below, to make payment to the
                   Transmission Provider on or before the due date as
                   described above, and such failure of payment is not
                   corrected within thirty (30) calendar days after the
                   Transmission Provider notifies the Transmission
                   Customer to cure such failure, a default by the
                   Transmission Customer shall be deemed to exist.  Upon
                   the occurrence of a default, the Transmission Provider
                   may initiate a proceeding with the Commission to
                   terminate service but shall not so terminate service
                   until the Commission so approves any such request.  In
                   the event of a billing dispute between the Transmission
                   Provider and the Transmission Customer, the
                   Transmission Provider will continue to provide service
                   under the Service Agreement as long as the Transmission
                   Customer (i) continues to make all payments not in
                   dispute, and (ii) pays into an independent escrow
                   account the portion of the invoice in dispute, pending
                   resolution of such dispute.  If the Transmission
                   Customer fails to meet these two requirements for
                   continuation of service, then the Transmission Provider
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                                                     Original Sheet No. 59
                   will provide notice to the Transmission Customer of its
                   intention to suspend service in 60 days, in accordance
                   with Commission policy.   
         22.0  Regulatory Filings
              Nothing contained in this Tariff or any Service Agreement
         shall be construed as affecting in any way the right of the
         Transmission Provider to unilaterally make application to the
         Commission for a change in rates, charges, classification of
         service, or any rule, regulation or Service Agreement related
         thereto, under Section 205 of the Federal Power Act and pursuant
         to the Commission's rules and regulations promulgated thereunder.
              Nothing contained in this Tariff or any associated Service
         Agreement shall be construed as affecting in any way the ability
         of any Party receiving service under the Tariff to exercise its
         rights under the Federal Power Act and pursuant to the
         Commission's rules and regulations promulgated thereunder.
         23.0  Liability and Indemnification
              Neither the Transmission Customer nor the Transmission
         Provider shall be liable to the other for damages for any act,
         omission, or circumstance occasioned by or in consequence of any
         act of God, labor disturbance, act of the public enemy, war,
         insurrection, riot, fire, storm or flood, explosion, breakage or
         accident to machinery or equipment, or by any other cause or
         causes beyond such Party's control, including any curtailment,
         order, regulation or restriction imposed by governmental military
         or lawfully established civilian authorities, or by the making of
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                                                     Original Sheet No. 60
         necessary repairs upon the property or equipment of either Party
         hereto.
              Notwithstanding the provisions of the foregoing paragraph,
         the Transmission Customer and the Transmission Provider shall at
         all times assume all liability for, and shall indemnify and save
         each other harmless from, any and all damages, losses, claims,
         demands, suits, recoveries, costs, and expenses, including all
         court costs and attorney fees, arising out of or resulting from,
         either directly or indirectly, their respective facilities, or
         the electric energy transmitted hereunder, whether such damages,
         losses, claims, demands, suits, recoveries, costs, and expenses
         result from any injury to or death of any person or persons
         whomsoever, or from any loss, destruction of, or damage to any
         property of any third party, or from any outages, or from any
         business interruption, or from any other cause whatsoever,
         occurring on their respective systems, or on the system(s) of
         parties served by the Transmission Customer or the Transmission
         Provider, or the Parties purchasing or transmitting the capacity
         and/or energy received or delivered by the Transmission Provider
         or the Transmission Customer pursuant to the Service Agreement,
         except in cases of gross negligence or intentional wrongdoing.
         24.0  Creditworthiness
              For the purpose of determining the ability of the
         Transmission Customer to meet its obligations related to service
         hereunder, the Transmission Provider may require reasonable
         credit review procedures.  This review shall be made in
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                                                     Original Sheet No. 61
         accordance with standard commercial practices.  In addition, the
         Transmission Provider may require the Transmission Customer to
         provide and maintain in effect during the term of the Service
         Agreement, an unconditional and irrevocable letter of credit as
         security to meet its responsibilities and obligations under this
         Tariff, or an alternative form of security proposed by the
         Transmission Customer and acceptable to the Transmission Provider
         and consistent with commercial practices established by the
         Uniform Commercial Code that protects the Transmission Provider
         against the risk of non-payment.  
         25.0  Dispute Resolution Procedures
            25.1   Internal Dispute Resolution Procedures - Any dispute
                   between a Transmission Customer (or Transmission
                   Customer, as appropriate) and the Transmission Provider
                   involving Transmission Service under this Tariff
                   (excluding applications for rate changes or other
                   changes to this Tariff, or to any Service Agreement
                   entered into under this Tariff, which shall be
                   presented directly to the Commission for resolution)
                   shall be referred to a designated senior representative
                   of the Transmission Provider and a senior
                   representative of the Transmission Customer for
                   resolution on an informal basis as promptly as
                   practicable.  In the event the designated
                   representatives are unable to resolve the dispute
                   within thirty (30) days, or such other period as the
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                   Parties may agree upon, if mutually agreeable, such
                   dispute may be submitted to arbitration and resolved in
                   accordance with the arbitration procedures set forth
                   below.   
            25.2   External Arbitration Procedures - Any arbitration
                   initiated under this Tariff shall be conducted before a
                   single neutral arbitrator appointed by the Parties.  If
                   the Parties fail to agree upon a single arbitrator
                   within ten (10) days of the referral of the dispute to
                   arbitration, each Party shall choose one arbitrator who
                   shall sit on a three-member arbitration panel.  The two
                   arbitrators so chosen shall within twenty (20) days
                   select a third arbitrator to chair the arbitration
                   panel.  In either case, the arbitrators shall be
                   knowledgeable in electric utility matters, including
                   electricity transmission and bulk power issues, and
                   shall not have any current or past substantial business
                   or financial relationships with any party to the
                   arbitration (except prior arbitration).  The
                   arbitrator(s) shall provide each of the parties an
                   opportunity to be heard and, except as otherwise
                   provided herein, shall generally conduct the
                   arbitration in accordance with the Commercial
                   Arbitration Rules of the American Arbitration
                   Association and any applicable Commission rules or as
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                   generally accepted in the region and consistently
                   adhered to by the Transmission Provider.
            25.3   Arbitration Decisions - Unless otherwise agreed, the
                   arbitrator(s) shall render a decision within ninety
                   (90) days of appointment and shall notify the parties
                   in writing of such decision and the reasons therefor.
                   The arbitrator(s) shall be authorized only to interpret
                   and apply the provisions of this Tariff and any Service
                   Agreement entered into under this Tariff and shall have
                   no power to modify or change any of the above in any
                   manner.  The decision of the arbitrator(s) shall be
                   final and binding upon the parties, and judgment on the
                   award may be entered in any court having jurisdiction.
                   The decision of the arbitrator(s) may be appealed
                   solely on the grounds that the conduct of the
                   arbitrator(s), or the decision itself, violated the
                   standards set forth in the Federal Arbitration Act
                   and/or the Administrative Dispute Resolution Act.  The
                   final decision of the arbitrator must also be filed
                   with the Commission if it affects jurisdictional rates,
                   terms or conditions of service or facilities.
            25.4   Costs - Each party shall be responsible for the
                   following costs, if applicable:
                    (i) its own costs incurred during the arbitration
                        process; and
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                   (ii) the cost of the arbitrator chosen by the party to
                        sit on the three member panel and one half of the
                        cost of the third arbitrator chosen; or
                  (iii) one half the cost of the single arbitrator jointly
                        chosen by the parties.
            25.5   Rights Under The Federal Power Act - Nothing in this
                   section shall restrict the rights of any party to file
                   a Complaint with the Commission under relevant
                   provisions of the Federal Power Act.  In addition, use
                   or application of the arbitration provisions in this
                   Section does not affect the jurisdiction of the
                   Commission over any matters arising under this Tariff.
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                                                     Original Sheet No. 65
                                    Schedule FTS
         Firm Transmission Service - The Transmission Customer shall
         compensate the Transmission Provider each month for Reserved
         Capacity at the sum of the applicable charges set forth below:
         1)   For Yearly delivery, one-twelfth of the demand charge of
              $     /KW of Reserved Capacity per year.
         2)   For Monthly delivery, $     /KW of Reserved Capacity per
              month.
         3)   For Weekly delivery, $     /KW of Reserved Capacity per
              week.
         4)   For Daily delivery, $     /KW of Reserved Capacity per day.
         5)   For Hourly delivery, $     /KW of Reserved Capacity per
              hour.
         6)   The total demand charge in any day, pursuant to a
              reservation for Hourly delivery, shall not exceed the rate
              specified in section (4) above times the highest amount in
              kilowatts of Reserved Capacity in any hour during such day.
              In addition, the total demand charge in any week, pursuant
              to a reservation for Hourly or Daily delivery, shall not
              exceed the rate specified in section (3) above times the
              highest amount in kilowatts of Reserved Capacity in any hour
              during such week.
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                                   Schedule STNF
         Short-Term Non-Firm Transmission Service - The Transmission
         Customer shall compensate the Transmission Provider for short-
         term non-firm Service as the sum of the applicable charges set
         forth below:
         1)   For Monthly delivery, $     /KW of Reserved Capacity per
              month.
         2)   For Weekly delivery, $     /KW of Reserved Capacity per
              week.
         3)   For Daily delivery, $     /KW of Reserved Capacity per day.
         4)   The total demand charge in any week, pursuant to a
              reservation for Daily delivery, shall not exceed the rate
              specified in section (2) above times the highest amount in
              kilowatts of Reserved Capacity in any day during such week.
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                                    Schedule HNF
         Hourly Non-Firm Transmission Service - The Transmission Customer
         shall compensate the Transmission Provider for Hourly Non-Firm
         Transmission Service as the sum of the applicable charges set
         forth below:
              Basic Charge:
              The basic charge shall be that agreed upon by the parties at
              the time this service is reserved and in no event shall
              exceed $        /MWH.  The total demand charge in any day,
              pursuant to a reservation for Hourly delivery, shall not
              exceed the rate specified in section (4) of Schedule STNF
              times the highest amount in kilowatts of Reserved Capacity
              in any hour during such day.  In addition, the total demand
              charge in any week, pursuant to a reservation for Hourly or
              Daily delivery, shall not exceed the rate specified in
              section (3) of Schedule STNF times the highest amount in
              kilowatts of Reserved Capacity in any hour during such week.
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                                     SCHEDULE 1
                             Loss Compensation Service
              Capacity and energy losses occur when a Transmission
         Provider delivers electricity across its transmission facilities
         for a Transmission Customer.  A Transmission Customer may elect
         to (1) supply the capacity and/or energy necessary to compensate
         the Transmission Provider for such losses, (2) receive an amount
         of electricity at delivery points that is reduced by the amount
         of losses incurred by the Transmission Provider, or (3) have the
         Transmission Provider supply the capacity and/or energy necessary
         to compensate for such losses.  The procedures to determine the
         amount of losses associated with a transaction are set forth
         below.  If loss compensation service is supplied by the
         Transmission Provider, the applicable charges for such service
         are set forth below.  Both the procedures for determining the
         amount of losses and the charges for loss compensation service
         must be consistent with the rate design of the transmission rates
         charged by the Transmission Provider.  To the extent another
         entity performs this service for the Transmission Provider,
         charges to the Transmission Customer are to reflect only a pass-
         through of the costs charged to the Transmission Provider by that
         entity.
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                                     SCHEDULE 2
                               Load Following Service
              Load following service is necessary to provide for the
         continuous balancing of resources (generation and interchange)
         with load under the control of the Transmission Provider (or
         other entity that performs this function for the Transmission
         Provider).  Load following service is accomplished by committing
         on-line generation whose output is raised or lowered
         (predominantly through the use of automatic generating control
         equipment) as necessary to follow the moment-by-moment changes in
         load.  The obligation to maintain this balance between resources
         and load lies with the Transmission Provider (or other entity
         that performs this function for the Transmission Provider).
         Because of the nature of this service, the Transmission Provider
         (or other entity that performs this function for the Transmission
         Provider's facilities) may be uniquely positioned to provide load
         following service.  Therefore, unless the Transmission Customer
         is able to obtain such service from its own generation or from
         third party generation that is capable of supplying such service
         consistent with Good Utility Practice, the Transmission Provider
         will supply load following service.  The charges for load
         following service are set forth below.  To the extent another
         entity performs this service for the Transmission Provider,
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 70
         charges to the Transmission Customer are to reflect only a pass-
         through of the costs charged to the Transmission Provider by that
         entity.
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 71
                                     SCHEDULE 3
                             System Protection Service
              A Transmission Provider must have adequate operating
         reserves or other system protection facilities available in order
         to maintain the integrity of its transmission facilities in the
         event of (1) unscheduled outages of a portion of its transmission
         facilities or facilities connected to the Transmission Provider's
         service territory or (2) unscheduled interruption of energy
         deliveries to the Transmission Provider's transmission
         facilities.  The amount of system protection service that must be
         supplied with respect to the Transmission Customer's transaction
         will be determined based on operating reserve margins or other
         relevant criteria that are generally accepted in the region and
         consistently adhered to by the Transmission Provider.
              The Transmission Customer may elect or arrange through a
         third party to provide resources that are sufficient to satisfy
         the system protection needs of the Transmission Provider.
         Operation and dispatch of such resources must be coordinated with
         the Transmission Provider or other entity that maintains
         operating reserves and other system protection facilities for the
         Transmission Provider's service territory.  Alternatively, if the
         Transmission Customer does not provide system protection service,
         the Transmission Provider will provide system protection service.
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 72
         The charges for system protection service are set forth below.
         To the extent another entity performs this service for the
         Transmission Provider, charges to the Transmission Customer are
         to reflect only a pass-through of the costs charged to the
         Transmission Provider by that entity.
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 73

                                     SCHEDULE 4
                              Energy Imbalance Service
              Energy Imbalance Service is provided when a difference
         occurs between the hourly scheduled amount and the hourly metered
         (actual delivered) amount associated with a transaction.
         Typically, an energy imbalance is eliminated during a future
         period by returning energy in-kind under conditions similar to
         those when the initial energy was delivered.  
              The Transmission Provider shall establish a deviation band
         (e.g., +/- 1.5 percent of the scheduled transaction) to be
         applied hourly to any energy imbalance that occurs as a result of
         the Transmission Customer's scheduled transaction(s).  Parties
         should attempt to eliminate energy imbalances within the limits
         of the deviation band within 30 days or reasonable period of time
         that is generally accepted in the region and consistently adhered
         to by the Transmission Provider.  If an energy imbalance is not
         corrected within 30 days or a reasonable period of time that is
         generally accepted in the region and consistently adhered to by
         the Transmission Provider, the Transmission Customer will
         compensate the Transmission Provider for such service.  Energy
         imbalances outside the deviation band will be subject to charges
         to be specified by the Transmission Provider.  The charges for
         energy imbalance service are set forth below.  To the extent
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 74
         another entity performs this service for the Transmission
         Provider, charges to the Transmission Customer are to reflect
         only a pass-through of the costs charged to the Transmission
         Provider by that entity.
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 75
                                     SCHEDULE 5
                       Reactive Power/Voltage Control Service
              In order to maintain transmission voltages on the
         Transmission Provider's transmission facilities within acceptable
         limits, transmission facilities and some or all generation
         facilities (in the service area where the Transmission Provider's
         transmission facilities are located) are operated to produce (or
         absorb) reactive power.  Thus, the need for reactive
         power/voltage control service must be considered for each
         transaction on the Transmission Provider's transmission
         facilities.  The amount of reactive power/voltage control service
         that must be supplied with respect to the Transmission Customer's
         transaction will be determined based on the reactive power
         support necessary to maintain transmission voltages within limits
         that are generally accepted in the region and consistently
         adhered to by the Transmission Provider.
              The Transmission Provider will be responsible for providing
         the necessary transmission-related reactive power support.  A
         Transmission Customer may elect (or arrange through a third
         party) to supply some or all of the necessary generation-related
         reactive power/voltage control support to the extent that it (or
         the third party) has the ability to supply such reactive power.  
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 76
         If the Transmission Customer elects (or arranges through a third
         party) to provide reactive power/voltage control support, such
         service must be coordinated with the Transmission Provider (or
         the entity that is responsible for the operation of the
         Transmission Provider's transmission facilities).  Alternatively,
         the Transmission Provider will supply the necessary generation-
         related reactive power/voltage control support.  The charges for
         such service will be based on the rates set forth below.  To
         avoid double counting in the development of the charge for
         reactive power/voltage control support, the Transmission Provider
         must take into consideration any transmission-related reactive
         power/voltage support charges that are included in the tariff
         transmission rates.  To the extent another entity performs this
         service for the Transmission Provider, charges to the
         Transmission Customer are to reflect only a pass-through of the
         costs charged to the Transmission Provider by that entity.
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 77
                                     SCHEDULE 6
                        Scheduling and Dispatching Services
              Scheduling is the control room procedure to establish a pre-
         determined (before-the-fact) use of generation resources and
         transmission facilities to meet anticipated load (including
         interchange).  Dispatching is the control room operation of all
         generation resources and transmission facilities on a real-time
         basis to meet load within the Transmission Provider's designated
         service area (or other larger area of coordinated dispatch
         operation).  Scheduling and dispatching services are to be
         provided by the Transmission Provider or other entity that
         performs scheduling and dispatching for the Transmission
         Provider's service territory.  The charges for scheduling and
         dispatch services are to be based on the rates set forth below.
         To the extent another entity performs these services for the
         Transmission Provider, charges to the Transmission Customer are
         to reflect only a pass-through of the costs charged to the
         Transmission Provider by that entity.
              In certain regions, dynamic scheduling is also allowed.  In
         these areas the Transmission Customer will be allowed to use
         dynamic scheduling when it is feasible and reliable.  Dynamic
         scheduling involves the arrangement for moving load or generation
         served within one Transmission Provider's service territory (or
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 78
         other larger area of coordinated dispatch operation) such that
         the load or generation is recognized in the real-time control and
         dispatch of another Transmission Provider.  Under dynamic
         scheduling, the operator of an area of coordinated dispatch
         (control area) agrees to assign certain customer load or
         generation to another area of coordinated dispatch, and to send
         the associated control signals to the respective control center
         of that area.  Dynamic scheduling is implemented through the use
         of specific telemetry and control equipment.  If the Transmission
         Provider supplies dynamic scheduling service to the Transmission
         Customer, the charges will be based on rates set forth below.  
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 79
                                     Appendix A
                 METHODOLOGY TO ASSESS TRANSFER CAPACITY AVAILABLE
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 80
                                      Appendix B
                              FORM OF SERVICE AGREEMENT
                              FIRM TRANSMISSION SERVICE
            1.0  This Service Agreement, dated as of _______________, is
                 entered into, by and between _____________ (the
                 Transmission Provider), and ____________ ("Transmission
                 Customer").
            2.0  The Transmission Customer has been determined by the
                 Transmission Provider to have a Valid Request for Firm
                 Transmission Service under the Transmission Provider's
                 Transmission Service Tariff ("Tariff").
            3.0  The Transmission Customer has provided to the
                 Transmission Provider an Application deposit in the
                 amount of $_________, which will be applied to charges
                 for service under this Agreement in accordance with the
                 provisions of Section 9 of the Tariff.
            4.0  Service under this agreement shall commence on the later
                 of: (l) __________________, or (2) the date on which
                 construction of any Direct Assignment Facilities and/or
                 Network Upgrades are completed, or (3) such other date as
                 it is permitted to become effective by the Commission.
                 Service under this agreement shall terminate on
                 _____________________.
            5.0  The Transmission Provider agrees to provide and the
                 Transmission Customer agrees to take and pay for Firm
                 Transmission Service in accordance with the provisions of
                 the Tariff and this Service Agreement.
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 81
            6.0  Any notice or request made to or by either Party
                 regarding this Service Agreement shall be made to the
                 representative of the other Party as indicated below.  
                 Transmission Provider:
                      _____________________________________
                      _____________________________________
                      _____________________________________
                 Transmission Customer:
                      _____________________________________
                      _____________________________________
                      _____________________________________
            7.0  The Tariff is incorporated herein and made a part hereof.
         IN WITNESS WHEREOF, the Parties have caused this Service Agreement
         to be executed by their respective authorized officials.

              Transmission Provider:
         By:______________________   _______________    ______________
            Name                     Title              Date
              Transmission Customer:
         By:______________________   _______________    ______________
            Name                     Title              Date
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 82
                   SPECIFICATIONS FOR FIRM TRANSMISSION SERVICE
         l.0  Term of Transaction: __________________________________
              Start Date: ___________________________________________
              Termination Date: _____________________________________
         2.0  Description of capacity and/or energy to be transmitted by
              Transmission Provider across the Transmission Provider's
              Transmission System (including electric control area in which
              the transaction originates).
              _______________________________________________________
         3.0  Point(s) of Receipt:___________________________________
              Receiving Party:_______________________________________
         4.0  Point(s) of Delivery:__________________________________
              Delivering Party:______________________________________
         5.0  Maximum amount of capacity and/or energy to be transmitted
              (Reserved Capacity):___________________________________
         6.0  Designation of party subject to reciprocal service
              obligation:_____________________________________________
         7.0  Name(s) of any Intervening Systems providing transmission
              service:________________________________________________
              ________________________________________________________
         8.0  Service under this Agreement may be subject to some combination
              of the charges detailed below.  (The appropriate charges for
              individual transactions will be determined in accordance with
              the terms and conditions of the tariff.)
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 83
              8.1  Embedded Cost Transmission Charge:________________
                   __________________________________________________
              8.2  Facilities Study Charge:__________________________
                   __________________________________________________
              8.3  Direct Assignment Facilities Charge:______________
                   __________________________________________________
              8.4  Ancillary Services Charge: _______________________
                   __________________________________________________
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 84
                                     Appendix C
                              FORM OF SERVICE AGREEMENT
                            NON-FIRM TRANSMISSION SERVICE
                               (Short-Term and Hourly)
           1.0  This Service Agreement, dated as of _______________, is
                entered into, by and between _______________ (the
                Transmission Provider), and ____________ ("Transmission
                Customer").
           2.0  The Transmission Customer has been determined by the
                Transmission Provider to be a Transmission Customer under
                the Transmission Provider's Transmission Service Tariff
                ("Tariff") and has filed a Completed Application for non-
                firm service in accordance with section 10 of the Tariff.
           3.0  Service under this Agreement shall be provided by the
                Transmission Provider upon request by the Transmission
                Customer.  Individual transactions may be scheduled
                telephonically (or in writing) between designated
                representatives of the parties.
           4.0  The Transmission Customer agrees to supply information
                the Transmission Provider deems reasonably necessary in
                accordance with Good Utility Practice in order for it to
                provide the requested service.
           5.0  The Transmission Provider agrees to provide and the
                Transmission Customer agrees to take and pay for non-firm
                transmission service in accordance with the provisions of
                the Tariff and this Service Agreement.
           6.0  Any notice or request made to or by either Party
                regarding this Service Agreement shall be made to the
                representative of the other Party as indicated below.  
                Transmission Provider:
                ____________________________________
                ____________________________________
                ____________________________________
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 85
                Transmission Customer:
                _____________________________________
                _____________________________________
                _____________________________________
           7.0  The Tariff is incorporated herein and made a part hereof.
           IN WITNESS WHEREOF, the Parties have caused this Service
           Agreement to be executed by their respective authorized
           officials.

           Transmission Provider:                                        
           By:__________________________ ________________  _____________
              Name                       Title             Date
           Transmission Customer:
           By:__________________________ ________________  _____________
              Name                       Title             Date

                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 86
                                     Appendix D
                  Methodology for Completing a System Impact Study
                                        Point-To-Point Transmission Tariff
                                                     Original Sheet No. 87
              INDEX OF CUSTOMERS UNDER FERC POINT-TO-POINT TRANSMISSION
                                    SERVICE TARIFF
                                                       Date of
                          Customer                     Service Agreement
                                                Appendix  C            
                       PRO-FORMA NETWORK INTEGRATION SERVICE
                                TRANSMISSION TARIFF
                                 TABLE OF CONTENTS
         Preamble
         1.0   Definitions . . . . . . . . . . . . . . . . . . . . . .   1
              1.1    Ancillary Services  . . . . . . . . . . . . . . .   1
              1.2    Annual Transmission Costs . . . . . . . . . . . .   2
              1.3    Application . . . . . . . . . . . . . . . . . . .   2
              1.4    Commission  . . . . . . . . . . . . . . . . . . .   2
              1.5    Control Area  . . . . . . . . . . . . . . . . . .   2
              1.6    Designated Agent  . . . . . . . . . . . . . . . .   3
              1.7    Direct Assignment Facilities  . . . . . . . . . .   3
              1.8    Eligible Customer . . . . . . . . . . . . . . . .   3
              1.9    Facilities Study  . . . . . . . . . . . . . . . .   3
              1.10   Good Utility Practice . . . . . . . . . . . . . .   4
              1.11   Load Ratio Share  . . . . . . . . . . . . . . . .   4
              1.12   Member System . . . . . . . . . . . . . . . . . .   4
              1.13   Native Load Customers . . . . . . . . . . . . . .   5
              1.14   Network Integration Transmission Service  . . . .   5
              1.15   Network Load  . . . . . . . . . . . . . . . . . .   5
              1.16   Network Operating Agreement . . . . . . . . . . .   6
              1.17   Network Operating Committee . . . . . . . . . . .   6
              1.18   Network Resource  . . . . . . . . . . . . . . . .   6
              1.19   Network Upgrade . . . . . . . . . . . . . . . . .   6
              1.20   Parties . . . . . . . . . . . . . . . . . . . . .   7
              1.21   Point-to-Point Transmission Service Tariff  . . .   7
              1.22   Regional Transmission Group . . . . . . . . . . .   7
              1.23   Service Agreement . . . . . . . . . . . . . . . .   7
              1.24   Service Commencement Date . . . . . . . . . . . .   7
              1.25   System Impact Study . . . . . . . . . . . . . . .   8
              1.26   Transmission Customer . . . . . . . . . . . . . .   8
              1.27   Transmission Provider . . . . . . . . . . . . . .   8
              1.28   Transmission System   . . . . . . . . . . . . . .   8
         2.0   Nature of Network Integration Service . . . . . . . . .   8
              2.1   Scope of Service . . . . . . . . . . . . . . . . .   8
              2.2   Firm Service . . . . . . . . . . . . . . . . . . .   9
              2.3   Non-Firm Service . . . . . . . . . . . . . . . . .   9
              2.4   Direct Assignment Facilities   . . . . . . . . . .  10
              2.5   Restrictions on Use of Service . . . . . . . . . .  10
         3.0   Availability of Network Integration Service . . . . . .  10
              3.1   General Conditions . . . . . . . . . . . . . . . .  10
              3.2   Network Operating Requirement  . . . . . . . . . .  11
              3.3   Transmission Provider Responsibilities . . . . . .  11
              3.4   Transmission Customer Redispatch Obligation  . . .  12
              3.5   Reciprocity  . . . . . . . . . . . . . . . . . . .  13
         4.0   Initiating Service  . . . . . . . . . . . . . . . . . .  13
                                         i
              4.1   Conditions Precedent for Receiving Service . . . .  13
              4.2   Application Procedures . . . . . . . . . . . . . .  14
              4.3   Technical Arrangements to be Completed Prior
                    to Commencement of Service . . . . . . . . . . . .  16
              4.4   Transmission Customer Facilities . . . . . . . . .  17
              4.5   Filing of Service Agreement  . . . . . . . . . . .  17
              4.6   Termination of Service . . . . . . . . . . . . . .  17
         5.0   Network Resources . . . . . . . . . . . . . . . . . . .  18
              5.1   Designation of Network Resources . . . . . . . . .  18
              5.2   Designation of New Network Resources . . . . . . .  18
              5.3   Termination of Network Resources . . . . . . . . .  19
              5.4   Operation of Network Resources . . . . . . . . . .  19
              5.5   Transmission Arrangements for Network
                    Resources Located Outside the Transmission
                    Provider's Control Area  . . . . . . . . . . . . .  20
              5.6   Limitation on Designation of Network Resources . .  20
              5.7   Transmission Customer Owned Transmission
                    Facilities . . . . . . . . . . . . . . . . . . . .  20
         6.0   Designation of Member Systems by Transmission
               Customers Receiving Network Integration Service . . . .  21
              6.1  Member Systems  . . . . . . . . . . . . . . . . . .  21
              6.2  New Member Systems Connected With the Transmission
                   Provider  . . . . . . . . . . . . . . . . . . . . .  21
              6.3  New Member Systems Not Connected with the
                   Transmission Provider   . . . . . . . . . . . . . .  22
              6.4  New Interconnection Points  . . . . . . . . . . . .  23
         7.0   Transmission Facilities or Upgrades Related to
               Designation of New Network Resources and Member
               Systems . . . . . . . . . . . . . . . . . . . . . . . .  24
              7.1   Queue Priority . . . . . . . . . . . . . . . . . .  24
              7.2   System Impact Study  . . . . . . . . . . . . . . .  24
              7.3   Facilities Study . . . . . . . . . . . . . . . . .  25
              7.4   Interconnection of New Member Systems  . . . . . .  26
              7.5   Transmission Facilities Associated with
                    Adding New Network Resources . . . . . . . . . . .  27
              7.6   Changes in Service Requests  . . . . . . . . . . .  27
              7.7   Annual Load and Resource Information Updates . . .  28
         8.0   Ancillary Services  . . . . . . . . . . . . . . . . . .  28
              8.1   Loss Compensation Service  . . . . . . . . . . . .  29
              8.2   Load Following Service . . . . . . . . . . . . . .  29
              8.3   System Protection Service  . . . . . . . . . . . .  29
              8.4   Energy Imbalance Service . . . . . . . . . . . . .  29
              8.5   Reactive Power/Voltage Control Service . . . . . .  29
              8.6   Scheduling and Dispatching Service . . . . . . . .  29
                                         ii
         9.0.  Load Shedding and Curtailments  . . . . . . . . . . . .  29
              9.1   Procedures . . . . . . . . . . . . . . . . . . . .  29
              9.2   Transmission Constraints . . . . . . . . . . . . .  30
              9.3   Cost Responsibility for Relieving Capacity
                    Constraints  . . . . . . . . . . . . . . . . . . .  31
              9.4   Curtailments of Scheduled Deliveries   . . . . . .  31
              9.5   Allocation of Curtailments   . . . . . . . . . . .  32
              9.6   Load Shedding  . . . . . . . . . . . . . . . . . .  32
              9.7   System Reliability . . . . . . . . . . . . . . . .  32
         10.0  Off-System and Third-Party Sales  . . . . . . . . . . .  34
         11.0  Rates and Charges . . . . . . . . . . . . . . . . . . .  34
              11.1  Monthly Demand Charge  . . . . . . . . . . . . . .  34
              11.2  Determination of Transmission Customer's Monthly
                    Network Load . . . . . . . . . . . . . . . . . . .  34
              11.3  Determination of the Transmission Provider's
                    Total Monthly Load . . . . . . . . . . . . . . . .  34
              11.4  Redispatch Charge  . . . . . . . . . . . . . . . .  35
              11.5  Stranded Cost Recovery . . . . . . . . . . . . . .  35
         12.0  Billing and Payment . . . . . . . . . . . . . . . . . .  35
              12.1  Billing Procedure  . . . . . . . . . . . . . . . .  35
              12.2  Interest on Unpaid Balances  . . . . . . . . . . .  36
              12.3  Customer Default . . . . . . . . . . . . . . . . .  36
         13.0  Booking of Costs Attributable to the
               Transmission Provider's Use of this Tariff  . . . . . .  37
         14.0  Standards of Conduct  . . . . . . . . . . . . . . . . .  38
              14.1  Standard of Nondiscrimination  . . . . . . . . . .  38
              14.2  Communications with Eligible Customers . . . . . .  38
              14.3  Standard of Due Diligence  . . . . . . . . . . . .  38
              14.4  Dispute Resolution Procedures  . . . . . . . . . .  39
         15.0  Indemnification and Liability . . . . . . . . . . . . .  39
         16.0  Regulatory Filings  . . . . . . . . . . . . . . . . . .  40
         17.0  Operating Arrangements  . . . . . . . . . . . . . . . .  41
              17.1  Operation Under The Network Operating Agreement  .  41
              17.2  Network Operating Agreement  . . . . . . . . . . .  41
         18.0  Network Operating Committee . . . . . . . . . . . . . .  42
         19.0  Resolution of Disputes  . . . . . . . . . . . . . . . .  43
                                        iii
              19.1  Internal Dispute Resolution Procedures . . . . . .  43
              19.2  External Arbitration Procedures  . . . . . . . . .  44
              19.3  Arbitration Decisions  . . . . . . . . . . . . . .  45
              19.4  Costs  . . . . . . . . . . . . . . . . . . . . . .  45
              19.5  Rights Under The Federal Power Act . . . . . . . .  46
         20.0  Creditworthiness  . . . . . . . . . . . . . . . . . . .  46
         Appendix A     Standard Form of Service Agreement . . . . . .  47
         Appendix B     Methodology for Completing a System Impact
                        Study  . . . . . . . . . . . . . . . . . . . .  48
         Appendix C     Standard Form of Network Operating Agreement .  49
         Schedule 1 - Annual Transmission Revenue Requirement  . . . .  50
         Schedule 2 - Loss Compensation Service  . . . . . . . . . . .  51
         Schedule 3 - Load Following Service . . . . . . . . . . . . .  52
         Schedule 4 - System Protection Service  . . . . . . . . . . .  54
         Schedule 5 - Energy Imbalance Service . . . . . . . . . . . .  56
         Schedule 6 - Reactive Power/Voltage Control Service . . . . .  58
         Schedule 7 - Scheduling and Dispatching Service . . . . . . .  60
         Index of Customers under FERC Network Integration Transmission
         Service Tariff  . . . . . . . . . . . . . . . . . . . . . . .  62
                                         iv
                                               Network Transmission Tariff
                                                      Original Sheet No. 1
         NETWORK INTEGRATION SERVICE TRANSMISSION TARIFF
         Preamble
              Transmission Provider will provide Network Integration
         Transmission Service pursuant to the terms and conditions
         contained in this Tariff and Service Agreement. The service the
         Transmission Provider will provide under this Tariff allows a
         Transmission Customer to integrate, economically dispatch and
         regulate its current and planned Network Resources to serve its
         Network Load in a manner comparable to that in which the
         Transmission Provider utilizes its Transmission System to serve
         its Native Load Customers.  Network Integration Transmission
         Service also may be used by the Transmission Customer to deliver
         non-firm energy purchases to its Network Load without additional
         charge.  Transmission service for third-party sales, which is not
         a Network Integration Transmission Service, will be provided
         under the Transmission Provider's Point-to-Point Transmission
         Service Tariff.
         1.0   Definitions
              1.1  Ancillary Services:  Ancillary services are those
                   services necessary to support the transmission of
                   energy from resources to loads while maintaining
                   reliable operation of the Transmission Provider's
                   transmission system in accordance with Good Utility
                   Practice.
                                               Network Transmission Tariff
                                                      Original Sheet No. 2
              1.2  Annual Transmission Costs:  The total annual cost of
                   the Transmission System shall be the amount specified
                   in Schedule 1 until amended by the Transmission
                   Provider or modified by the Commission.  
              1.3  Application:  A request by an Eligible Customer for
                   Network Integration Service pursuant to the provisions
                   of this Tariff.
              1.4  Commission:  The Federal Energy Regulatory Commission.
              1.5  Control Area:  An electric power system or combination
                   of electric power systems to which a common automatic
                   generation control scheme is applied in order to:
                   (1)  match, at all times, the power output of the
                        generators within the electric power system(s) and
                        capacity and energy purchased from entities
                        outside the electric power system(s), with the
                        load within the electric power system(s);
                   (2)  maintain, within the limits of Good Utility
                        Practice, scheduled interchange with other Control
                        Areas;
                   (3)  maintain the frequency of the electric power
                        system(s) within reasonable limits in accordance
                        with Good Utility Practice; and
                   (4)  provide sufficient generating capacity to maintain
                        operating reserves in accordance with Good Utility
                        Practice.
                                               Network Transmission Tariff
                                                      Original Sheet No. 3
              1.6  Designated Agent:  Any entity that performs actions or
                   functions on behalf of the Transmission Provider, an
                   Eligible Customer, or the Transmission Customer
                   required under this Tariff.
              1.7  Direct Assignment Facilities:  Facilities that are
                   constructed by the Transmission Provider to facilitate
                   a specific request for service under this tariff, with
                   costs that the Commission permits to be directly
                   assigned to the Transmission Customer requesting the
                   service.  Direct Assignment Facilities shall be
                   specified in the Service Agreement that governs service
                   to the Customer.
              1.8  Eligible Customer:  Any of the following:  (i) the
                   Transmission Provider (for its own Network Integration
                   Transmission use of the Transmission System); (ii) any
                   electric utility, Federal power marketing agency, or
                   any other person generating electric energy for sale
                   for resale; and (iii) any designated agent for an
                   Eligible Customer.  
              1.9  Facilities Study:  An engineering study conducted by
                   the Transmission Provider to determine the required
                   modifications to the Transmission Provider's
                   Transmission System, including the cost and scheduled
                   completion date for such modifications, that will be
                   required to provide a requested Network Integration
                   Service, to add a new Network Transmission Customer, to
                                               Network Transmission Tariff
                                                      Original Sheet No. 4
                   add a new Member System, or to add a Network Resource,
                   in accordance with the results of the System Impact
                   Study.
             1.10  Good Utility Practice:  Any of the practices, methods
                   and acts engaged in or approved by a significant
                   portion of the electric utility industry during the
                   relevant time period, or any of the practices, methods
                   and acts which, in the exercise of reasonable judgment
                   in light of the facts known at the time the decision
                   was made, could have been expected to accomplish the
                   desired result at the lowest reasonable cost consistent
                   with good business practices, reliability, safety and
                   expedition.  Good Utility Practice is not intended to
                   be limited to the optimum practice, method, or act, to
                   the exclusion of all others, but rather to be
                   acceptable practices, methods, or acts generally
                   accepted in the region and consistently adhered to by
                   the Transmission Provider.
             1.11  Load Ratio Share:  Ratio of a Transmission Customer's
                   Network Load to the Transmission Provider's total load
                   computed in accordance with Sections 11.2 and 11.3 and
                   calculated on a rolling twelve month basis.  
             1.12  Member System:  An Eligible Customer operating as a
                   part of a lawful combination, partnership, association
                   or joint action agency composed exclusively of Eligible
                   Customers.
                                               Network Transmission Tariff
                                                      Original Sheet No. 5
             1.13  Native Load Customers:  Those wholesale and retail
                   customers on whose behalf the Transmission Provider, by
                   statute, franchise, regulatory requirement or contract,
                   has an obligation to construct and operate the
                   Transmission Provider's system to meet the reliable
                   electric needs of such customers.
             1.14  Network Integration Transmission Service:  Network
                   Integration Transmission Service allows a Transmission
                   Customer to integrate, plan, economically dispatch and
                   regulate its Network Resources to serve its Network
                   Load in a manner comparable to that in which the
                   Transmission Provider utilizes its Transmission System
                   to serve its Native Load Customers.  Network
                   Integration Transmission Service also may be used by
                   the Transmission Customer to deliver non-firm energy
                   purchases to its Network Load without additional
                   charge.  
             1.15  Network Load:  The designated load of a Transmission
                   Customer, including the entire load of all Member
                   Systems designated pursuant to Section 6.0.  A
                   Transmission Customer's Network Load shall not be
                   reduced to reflect any portion of such load served by
                   the output of any generating facilities owned, or
                   generation purchased, by the Transmission Customer or
                   its Member Systems.
                                               Network Transmission Tariff
                                                      Original Sheet No. 6
             1.16  Network Operating Agreement:  An agreement that
                   contains the terms and conditions under which the
                   Transmission Customer shall operate its facilities and
                   the technical and operational matters associated with
                   the implementation of this Tariff.
             1.17  Network Operating Committee:  A group made up of
                   representatives from the Transmission Customers and the
                   Transmission Provider established to coordinate
                   operating criteria and other technical considerations
                   required for implementation of this tariff.
             1.18  Network Resource:  Any owned and/or purchased
                   Transmission Customer generating resource that is
                   located in the Transmission Provider's control area or
                   connected to the Electric System of any Transmission
                   Customer or any Member System, with the exception of
                   any resource, or any portion thereof, that is committed
                   for sale to third parties or otherwise cannot be called
                   upon to meet the Transmission Customer's Network Load
                   on a non-interruptible basis.  A Transmission Customer
                   also may designate as a Network Resource a generating
                   resource (or portion thereof) located in another
                   control area or power purchased by the Transmission
                   Customer from generation located in another control
                   area.  
             1.19  Network Upgrade:  A modification and/or addition to
                   transmission facilities that is integrated with and
                                               Network Transmission Tariff
                                                      Original Sheet No. 7
                   supports the Transmission Provider's Transmission
                   System and which is constructed by the Transmission
                   Provider to satisfy, at least in part, an Application,
                   the addition of a new Member System, or the addition of
                   a new Network Resource.
             1.20  Parties:  The Transmission Provider and Transmission
                   Customer receiving service under this Tariff.
             1.21  Point-to-Point Transmission Service Tariff:  The
                   Transmission Provider's Point-to-Point Transmission
                   Service Tariff as such tariff may be amended and/or
                   superseded from time to time.
             1.22  Regional Transmission Group:  A voluntary organization
                   of transmission owners, transmission users and other
                   entities approved by the Commission to efficiently
                   coordinate transmission planning (and expansion),
                   operation and use on a regional (and interregional)
                   basis.
             1.23  Service Agreement:  The initial agreement and any
                   supplements thereto entered into by the Transmission
                   Customer and the Transmission Provider for service
                   under this Tariff.  
             1.24  Service Commencement Date:  The date the Transmission
                   Provider begins to provide service pursuant to the
                   terms of an executed Service Agreement or the date the
                   Transmission Provider begins to provide service in
                   accordance with Section 4.1 of this Tariff.
                                               Network Transmission Tariff
                                                      Original Sheet No. 8
             1.25  System Impact Study:  An assessment by the Transmission
                   Provider of (i) the adequacy of the Transmission System
                   to accommodate a request for firm Transmission Service
                   and/or (ii) whether any costs would be incurred in
                   order to provide transmission service.
             1.26  Transmission Customer:  Any Eligible Customer (or its
                   designated agent) that executes a service agreement
                   and/or receives transmission service under this Tariff.
             1.27  Transmission Provider:  The public utility (or its
                   designated agent) that owns or controls facilities used
                   for the transmission of electric energy in interstate
                   commerce and provides transmission service under this
                   Tariff.
             1.28  Transmission System:  The facilities owned, controlled,
                   operated or supported by the Transmission Provider
                   and/or Transmission Customer that are used to provide
                   transmission service under this Tariff.
         2.0   Nature of Network Integration Service
              2.1  Scope of Service:  Network Integration Service is a
                   transmission service that allows Transmission Customers
                   to efficiently and economically utilize their Network
                   Resources and other generation resources to serve their
                   Network Load located in the Transmission Provider's
                   control area and any additional load that may be
                   designated pursuant to Section 6.0.  A Network
                   Integration Service Transmission Customer must obtain
                                               Network Transmission Tariff
                                                      Original Sheet No. 9
                   or provide certain Ancillary Services under a Network
                   Operating Agreement.  The Transmission Provider will
                   offer these Ancillary Services on a non-discriminatory
                   basis to any Eligible Customer required hereunder to
                   purchase or provide such services as a precondition to
                   receiving Network Integration Service.
              2.2  Firm Service:  A Transmission Customer shall have the
                   right to use the Transmission Provider's Transmission
                   System for the delivery of power from Network Resources
                   to Network Loads on a basis that is comparable to the
                   Transmission Provider's use of its Transmission System
                   to reliably serve its Native Load Customers.  Service
                   over the Transmission Provider's Transmission System
                   for the delivery of power from Network Resources to
                   Network Load shall have priority over all non-firm uses
                   of the Transmission Provider's Transmission System by
                   the Transmission Provider or third parties.
              2.3  Non-Firm Service:  A Transmission Customer may use the
                   Transmission Provider's Transmission System to deliver
                   energy to its Network Loads from resources that have
                   not been designated as Network Resources.  Such energy
                   shall be delivered on a non-firm, capacity available
                   basis, at no additional charge.  Deliveries from
                   resources other than Network Resources will have a
                   higher curtailment priority than non-firm service under
                                               Network Transmission Tariff
                                                     Original Sheet No. 10
                   the Transmission Provider's Point-to-Point Transmission
                   Service Tariff.
              2.4  Direct Assignment Facilities:  The Service Agreement
                   for Network Integration Service will establish the use
                   of, and the cost for, service over directly assigned
                   facilities.
              2.5  Restrictions on Use of Service:  Network Integration
                   Service shall not be used for (i) wholesale sales of
                   capacity or energy to third parties, or (ii) direct or
                   indirect provision of transmission service by the
                   Transmission Customer to third parties.  All Network
                   Integration Service Transmission Customers and the
                   Transmission Provider shall use the Transmission
                   Provider's Point-to-Point Transmission Service Tariff
                   for off-system or third party sales.
         3.0.  Availability of Network Integration Service
              3.1  General Conditions:  In accordance with the provisions
                   of this Tariff, Network Integration Service shall be
                   provided by the Transmission Provider to allow a
                   Transmission Customer to integrate, plan, economically
                   dispatch and regulate its Network Resources to serve
                   its Network Load in a manner comparable to that in
                   which the Transmission Provider utilizes its
                   Transmission System to serve its Native Load Customers.
                   Network Integration Transmission Service also may be
                   used by the Transmission Customer to deliver non-firm
                                               Network Transmission Tariff
                                                     Original Sheet No. 11
                   energy purchases to its Network Load without additional
                   charge.  Transmission service for off-system and third-
                   party sales, which is not a Network Integration
                   Transmission Service, will be provided under the
                   Transmission Provider's Point-to-Point Transmission
                   Service Tariff.
              3.2  Network Operating Requirement:  As a condition to
                   obtaining Network Integration Service, the Transmission
                   Customer shall execute a Network Operating Agreement
                   with the Transmission Provider.  The Network Operating
                   Agreement will recognize that the Transmission Customer
                   shall either: (i) operate as a control area under
                   applicable guidelines of the North American Electric
                   Reliability Council (NERC) and the [applicable regional
                   reliability council] or (ii) satisfy its control area
                   requirements, including all Ancillary Services, by
                   contracting with the Transmission Provider or (iii)
                   satisfy its control area requirements, including all
                   Ancillary Services, by contracting with another entity
                   consistent with Good Utility Practice which satisfies
                   NERC national and regional requirements.  The
                   Transmission Provider shall not unreasonably refuse to
                   accept contractual arrangements with another entity for
                   Ancillary Services .  
              3.3  Transmission Provider Responsibilities:  The
                   Transmission Provider will plan, construct, operate and
                                               Network Transmission Tariff
                                                     Original Sheet No. 12
                   maintain its Transmission System in accordance with
                   Good Utility Practice in order to provide the
                   Transmission Customer with Network Integration Service
                   over the Transmission Provider's Transmission System in
                   accordance with this Tariff.  The Transmission Provider
                   shall include the Transmission Customer's Network Load
                   in its transmission system planning and shall,
                   consistent with Good Utility Practice, endeavor to
                   construct and place into service sufficient
                   transmission capacity to deliver the Transmission
                   Customer's Network Resources to serve Network Load on a
                   basis comparable to the Transmission Provider's
                   delivery of its own generating and purchased resources
                   to the Transmission Provider's Native Load Customers.  
              3.4  Transmission Customer Redispatch Obligation:  As a
                   condition to receiving Network Integration Service, a
                   Transmission Customer agrees to redispatch its Network
                   and other resources as requested by the Transmission
                   Provider to create additional firm transmission
                   capacity on the Transmission Provider's Transmission
                   System to allow the Transmission Provider to provide
                   new firm transmission service to third parties under
                   this tariff or under the Transmission Provider's Point-
                   to-Point Transmission Service Tariff.  To the extent
                   practical, the redispatch of resources pursuant to this
                   Section shall be on a least cost, non-discriminatory
                                               Network Transmission Tariff
                                                     Original Sheet No. 13
                   basis as between all Network Integration Transmission
                   Customers and the Transmission Provider.
              3.5  Reciprocity:  A Transmission Customer receiving
                   transmission service under this Tariff agrees to
                   provide comparable service to the Transmission Provider
                   on similar terms and conditions over facilities owned
                   or controlled by the Transmission Customer and its
                   affiliates.  A Transmission Customer that has on file
                   with the Commission transmission tariffs of general
                   applicability that meet the Commission's comparability
                   of service standard shall be deemed to meet this
                   reciprocity requirement.  
         4.0.  Initiating Service
              4.1  Conditions Precedent for Receiving Service:  Subject to
                   the terms and conditions of this Tariff, the
                   Transmission Provider will provide Network Integration
                   Service to any Eligible Customer, provided that (i) the
                   Eligible Customer has completed an Application for
                   service as provided under this Tariff, (ii) the
                   Eligible Customer and the Transmission Provider have
                   completed the technical arrangements set forth in
                   Section 4.3 below and (iii) the Eligible Customer has
                   executed a Service Agreement for service under this
                   Tariff and for deliveries over Direct Assignment
                   Facilities, if necessary, or requested in writing that
                   the Transmission Provider file a proposed unexecuted
                                               Network Transmission Tariff
                                                     Original Sheet No. 14
                   Service Agreement with the Commission.  The form of
                   such Service Agreement is provided in Appendix A.
              4.2  Application Procedures:  An Eligible Customer
                   requesting service under this Tariff must submit an
                   Application to the Transmission Provider as far as
                   possible in advance of the calendar month in which
                   service is to commence.  A completed Application shall
                   provide all of the information included in 18 CFR §
                   2.20 including but not limited to the following:
                   (i)  The identity, address, telephone number and
                        facsimile number of the party requesting service.
                  (ii)  A statement that the party requesting service is,
                        or will be upon commencement of service, an
                        Eligible Customer under this Tariff.  
                 (iii)  A description of the Network Load
                        (subdivided into the load of any Member Systems
                        whose loads are designated as Network Load).  This
                        description should separately identify and provide
                        the Eligible Customer's best estimate of the total
                        loads to be served at each transmission voltage
                        level, and the loads to be served from each
                        Transmission Provider substation at the same
                        transmission voltage level.  The description
                        should include a ten (10) year forecast of summer
                        and winter load and resource requirements
                        beginning with the first year after the service is
                        scheduled to commence.
                  (iv)  The amount and location of any interruptible loads
                        included in the Network load.  This shall include
                        the summer and winter capacity requirements for
                        each interruptible load (had such load not been
                        curtailed), that portion of the load subject to
                        curtailment, the conditions under which a
                        curtailment can be implemented and any limitations
                        on the amount and frequency of curtailments.  An
                        Eligible Customer should identify the amount of
                        curtailed customer load (if any) included in the
                        10 year load forecast provided in response to
                        (iii) above.  
                                               Network Transmission Tariff
                                                     Original Sheet No. 15
                   (v)  A description of Network Resources (current and
                        10-year projection), which shall include, for each
                        Network Resource:
                        -    Unit size and amount of capacity from that
                             unit to be designated as Network Resource
                        -    VAR capability (both leading and lagging) of
                             all generators
                        -    Operating restrictions
                             -    Any periods of restricted operations
                                  throughout the year
                             -    Minimum loading level of unit
                             -    Normal operating level of unit
                             -    Any must-run unit designations required
                                  for system reliability or contract
                                  reasons
                        -    Approximate variable generating cost ($/MWH)
                             for redispatch computations
                        -    Arrangements governing sale and delivery of
                             power to third parties from generating
                             facilities located in the Transmission
                             Provider control area, where only a portion
                             of unit output is designated as a Network
                             Resource
                        -    Description of purchased power designated as
                             a Network Resource including source of
                             supply, control area location, transmission
                             arrangements and delivery point(s) to the
                             Transmission Provider Transmission System.
                   (vi) Description of Eligible Customer's Transmission
                        System:
                        -    Load flow and stability data, such as real
                             and reactive parts of the load, lines,
                             transformers, reactive devices and load type,
                             including normal and emergency ratings of all
                             transmission equipment in a load flow format
                             compatible with that used by the Transmission
                             Provider
                        -    Operating restrictions needed for reliability
                        -    Operating guides employed by system operators
                        -    Contractual restrictions or committed uses of
                             the Eligible Customer's Transmission System,
                             other than the Eligible Customer's Network
                             Loads and Resources
                        -    Location of Network Resources described in
                             subsection 4.2(v)
                        -    10 year projection of system expansions or
                             upgrades
                        -    Transmission system maps that include any
                             proposed expansions or upgrades
                                               Network Transmission Tariff
                                                     Original Sheet No. 16
                        -    Thermal ratings of Eligible Customer's
                             Control Area ties with other control areas.
                  (vii) Service commencement date and the term of the
                        requested Network Integration Service.
                   Unless the parties agree to a different time frame, the
                   Transmission Provider must acknowledge the request
                   within ten (10) days of receipt.  The acknowledgement
                   must include a date by which a response will be sent to
                   the Eligible Customer and a statement of any fees
                   associated with responding to the request (e.g., system
                   impact studies).  If an Application fails to meet the
                   requirements of this Tariff, the Transmission Provider
                   shall notify the Eligible Customer requesting service
                   within fifteen (15) days of receipt and specify the
                   reasons for such failure.  Wherever possible, the
                   Transmission Provider will attempt to remedy
                   deficiencies in the Application through informal
                   communications with the Eligible Customer.  The
                   Transmission Provider will not divulge information from
                   the Application to its Marketing Department.
              4.3  Technical Arrangements to be Completed Prior to
                   Commencement of Service:  Service under this Tariff
                   shall not commence until the Transmission Provider and
                   the Transmission Customer, or a third party, have
                   completed installation of all equipment specified under
                   the Network Operating Agreement consistent with
                   national and regional guidelines and any additional
                                               Network Transmission Tariff
                                                     Original Sheet No. 17
                   requirements reasonably and consistently imposed to
                   ensure the reliable operation of the Transmission
                   System.  The Transmission Provider shall exercise
                   reasonable efforts, in coordination with the
                   Transmission Customer, to complete such arrangements as
                   soon as practical prior to the Service Commencement
                   Date.
              4.4  Transmission Customer Facilities:  The provision of
                   Network Integration Transmission Service shall be
                   conditioned upon the Transmission Customer's
                   constructing, maintaining and operating the facilities
                   on its side of each point of interconnection that are
                   necessary to reliably interconnect and deliver power
                   from the Transmission System to the Transmission
                   Customer and/or its Member Systems.  The Transmission
                   Customer shall be solely responsible for constructing
                   and/or installing all facilities on the Transmission
                   Customer's side of each such interconnection point.
              4.5  Filing of Service Agreement:  The Transmission Provider
                   will file Service Agreements with the Commission in
                   compliance with applicable Commission regulations.  
              4.6  Termination of Service:  A Transmission Customer may
                   terminate service under this Tariff no earlier than 2
                   years after providing the Transmission Provider with
                   written notice of the Transmission Customer's intention
                   to terminate.  A Transmission Customer's provision of
                                               Network Transmission Tariff
                                                     Original Sheet No. 18
                   notice to terminate service under this Tariff shall not
                   relieve the Transmission Customer of its obligation to
                   pay the Transmission Provider any rates, charges, or
                   fees, including charges related to the construction of
                   Direct Assignment Facilities, for service previously
                   provided under the applicable Service Agreement or the
                   Network Operating Agreement, and which are owed to the
                   Transmission Provider as of the date of termination.
         5.0   Network Resources
              5.1  Designation of Network Resources:  Network Resources
                   shall include all generation owned or purchased by the
                   Transmission Customer, except for capacity sold to
                   third parties.  All of the owned and/or purchased
                   resources that were serving such Transmission
                   Customer's or its Member Systems' loads under firm
                   agreements entered into on or before the Service
                   Commencement Date shall initially be designated as
                   Network Resources.  Such Network Resources shall remain
                   Network Resources until the Transmission Customer
                   terminates the designation of such resources.  
              5.2  Designation of New Network Resources:  A Transmission
                   Customer may designate a new Network Resource by
                   providing the Transmission Provider with as much
                   advanced notice as practicable.  Until the Transmission
                   Provider has completed any transmission facilities or
                   upgrades determined in accordance with Section 7 to be
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                   necessary for firm delivery of a new Network Resource
                   to the Transmission Customer's Network Load, delivery
                   of power from such Network Resource will be provided by
                   the Transmission Provider, but only to the extent that
                   such service does not impair the reliability of service
                   to Native Load Customers, firm Point-to-Point
                   transmission customers, or other Network Integration
                   Service Customers.  Notice of a Transmission Customer's
                   intent to designate a new Network Resource shall
                   include sufficient engineering and technical
                   information to permit the Transmission Provider to
                   perform a System Impact Study addressing the
                   transmission requirements associated with delivery of
                   such new Network Resource to the Transmission
                   Customer's Network Load.  
              5.3  Termination of Network Resources:  A Transmission
                   Customer may terminate the designation of all or part
                   of a generating resource as a Network Resource if the
                   Transmission Customer provides notification to the
                   Transmission Provider as soon as reasonably practical,
                   but no less than 60 days before such termination.
              5.4  Operation of Network Resources:  A Transmission
                   Customer shall not operate its generating facilities
                   located in the Transmission Customer's or Transmission
                   Provider's control area such that the output of those
                   facilities exceeds the sum of (i) the capacity from
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                   those facilities that has been designated as a Network
                   Resource plus (ii) the amount of power from those
                   facilities scheduled for delivery to a third party
                   under the Transmission Provider's Point-to-Point
                   Tariff.  Transmission Customer shall arrange
                   transmission service under the Transmission Provider's
                   Point-to-Point Transmission Service Tariff for all
                   third-party sales.
              5.5  Transmission Arrangements for Network Resources Located
                   Outside the Transmission Provider's Control Area:  It
                   shall be the Transmission Customer's responsibility to
                   make any transmission arrangements necessary for
                   delivery of capacity and energy produced from a Network
                   Resource located outside the Transmission Provider's
                   control area to the Transmission System.  
              5.6  Limitation on Designation of Network Resources:  A
                   Transmission Customer shall designate an amount (in MW)
                   of Network Resources that it owns or has committed to
                   purchase pursuant to an executed contract, or such
                   other evidence establishing that execution of a
                   contract is contingent upon the availability of
                   transmission service under this Tariff.
              5.7  Transmission Customer Owned Transmission Facilities:  
                   The Transmission Customer is entitled to receive a
                   credit for existing transmission facilities it owns if
                   such facilities are integrated with, and support the
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                   Transmission Provider's Transmission system.
                   Calculation of the credit shall be addressed in the
                   Transmission Customer's Service Agreement.  For
                   facilities constructed by the Transmission Customer
                   subsequent to the initiation of service under this
                   Tariff, the Transmission Customer shall receive credit
                   where such facilities are jointly planned and installed
                   in coordination with the Transmission Provider.
         6.0.  Designation of Member Systems by Transmission Customers     
               Receiving Network Integration Service
              6.1  Member Systems:  A Transmission Customer may designate
                   the individual Member Systems on whose behalf the
                   Transmission Provider will provide Network Integration
                   Service.  The Member Systems shall be specified in the
                   Service Agreement.  
              6.2  New Member Systems Connected With the Transmission
                   Provider:  A Transmission Customer shall provide the
                   Transmission Provider with as much advanced notice as
                   reasonably practicable of the designation of additional
                   entities that will be added to its Control Area as new
                   Member Systems.  The Transmission Provider shall
                   provide Network Integration Service for any such new
                   Member System, provided that (i) the Transmission
                   Provider reasonably determines in accordance with
                   Section 7.0 that the Transmission System can reliably
                   accommodate such new Member System and (ii) the
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                   Transmission Customer agrees to pay the costs of any
                   Direct Assignment facilities that the Transmission
                   Provider reasonably determines must be installed to
                   serve reliably such new Member System with the
                   Transmission Provider Transmission System where such
                   costs are assigned to the Transmission Customer in
                   accordance with applicable Commission policy.  The
                   engineering and technical specifications for any such
                   upgrades shall be set forth in a supplement to the
                   Service Agreement under the Tariff.  Until such Direct
                   Assignment facilities are completed, the Transmission
                   Provider will agree to provide Network Integration
                   Service out of existing transmission capacity to the
                   extent such service would not impair the reliability of
                   service to Native Load Customers, firm Point-to-Point
                   transmission service customers and other Network
                   Integration Service Transmission Customers.
              6.3  Member Systems Not Connected with the Transmission
                   Provider:  This Section applies to both initial
                   designation pursuant to Section 6.1 and the subsequent
                   addition of new member systems.  To the extent that a
                   Transmission Customer desires to obtain transmission
                   service for a Member System that is not connected to
                   the Transmission Provider's Transmission System, the
                   Transmission Customer shall have the option of: (1)
                   electing to include such Member System by including the
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                   entire load of that Member System as Network Load for
                   all purposes under this Tariff and designating Network
                   Resources in connection with such additional Network
                   Load, or (2) excluding the load of that Member System
                   from its Network Load and purchasing point-to-point
                   transmission service under the Transmission Provider's
                   Point-to-Point Transmission Service Tariff.  To the
                   extent that a Transmission Customer gives notice of its
                   intent to add a Member System as part of its network
                   load pursuant to this section, and sufficient capacity
                   is not available on the Transmission System to provide
                   the requested service, the Transmission Provider shall
                   perform a Facilities Study pursuant to Section 7.3.  
              6.4  New Interconnection Points:  To the extent a
                   Transmission Customer desires to add a newly
                   constructed interconnection point between the
                   Transmission Provider's Transmission System and a
                   Member System, a Transmission Customer shall provide
                   the Transmission Provider with as much advance notice
                   as reasonably practicable; however, the Transmission
                   Provider shall not be obligated to provide additional
                   service with respect to such interconnection point
                   until such new interconnection is established.  The
                   Transmission Provider shall add such new
                   interconnection point provided that the Transmission
                   Provider reasonably determines that the Transmission
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                   Provider's Transmission System can reliably accommodate
                   such new interconnection point.  The engineering and
                   technical specifications for such new interconnection
                   point shall be set forth in an agreement to be
                   negotiated by the Parties and the charges will be filed
                   by the Transmission Provider as a supplement to the
                   Service Agreement under this Tariff.  
         7.0   Transmission Facilities or Upgrades Related to Designation
               of New Network Resources and Member Systems
              7.1  Queue Priority:  Applications for (1) Network
                   Integration Service, (ii) new Network Resources, or
                   (iii) new Member Systems, along with applications for
                   firm service under the Transmission Provider's Point-
                   to-Point Transmission Service Tariff, will be assigned
                   a priority according to the date and time upon which
                   the Application is received, with the earliest
                   Application receiving the highest priority.
              7.2  System Impact Study:  Once a Transmission Customer
                   provides the Transmission Provider with notice of its
                   intent to designate a new Network Resource pursuant to
                   Section 5.2, or a new Member System pursuant to
                   Sections 6.2 and 6.3, the Transmission Provider and the
                   Transmission Customer shall execute an agreement (Study
                   Agreement) under which the Transmission Provider will
                   perform a System Impact Study to determine the
                   feasibility of integrating such new Network Resource or
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                   new Member System into the Transmission Provider's
                   Transmission System.  In performing the System Impact
                   Study, the Transmission Provider shall apply the same
                   methods and criteria that it employs in integrating new
                   resources acquired by the Transmission Provider to
                   serve the Transmission Provider's Native Load
                   Customers.  The Transmission Provider shall complete
                   the System Impact Study within 60 days beginning on the
                   date of receipt of the executed Study Agreement.  In
                   the event the Transmission Provider is unable to
                   complete the study within the 60 day period, the
                   Transmission Provider will provide the Transmission
                   Customer a written explanation of when the study will
                   be completed and the reasons for the delay.  A
                   Transmission Customer shall be responsible for the cost
                   of the System Impact Study and shall be provided with
                   the results thereof, including relevant workpapers.
                   The Transmission Provider's methodology for completing
                   a System Impact Study is set forth in Appendix B.
              7.3  Facilities Study:  Based on the results of the System
                   Impact Study, the Transmission Provider also may
                   perform, pursuant to an executed agreement (Facilities
                   Study Agreement) with the Transmission Customer, a
                   Facilities Study addressing the detailed engineering,
                   design and cost of transmission facilities.  The
                   Facilities Study will be completed as soon as
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                   reasonably practicable and will be used by the
                   Transmission Provider to provide the Transmission
                   Customer with a binding estimate of the cost for
                   constructing facilities.  The Transmission Customer
                   shall be responsible for the cost of the Facilities
                   Study pursuant to the terms of the Facilities Study
                   Agreement and shall be provided with the results
                   thereof, including relevant workpapers.  The
                   Transmission Provider shall be responsible for the
                   costs of any Facilities Study undertaken to determine
                   the engineering, design and cost of facilities
                   associated with the Transmission Provider's addition of
                   new resources used to serve the Transmission Provider's
                   load.  Such costs will be booked by the Transmission
                   Provider in accordance with Section 13.0.
              7.4  Interconnection of New Member Systems:  The
                   Transmission Provider will use due diligence to install
                   any transmission facilities required to interconnect a
                   new Member System designated by the Transmission
                   Customer in accordance with Section 6.3.  The costs of
                   new facilities required to interconnect a new Member
                   System shall be determined in accordance with the
                   procedures provided in Sections 6.2 and 6.3 and shall
                   be charged to the Transmission Customer in accordance
                   with Commission policies.  Such charges shall be
                   reflected in a supplement to the Service Agreement.  
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              7.5  Transmission Facilities Associated with Adding New
                   Network Resources:  For purposes of this Section, new
                   resources shall include those resources designated as
                   Network Resources which are not in service as of the
                   Service Commencement Date.  The engineering and
                   technical specifications for transmission facilities
                   associated with adding new Network Resources shall be
                   set forth in an agreement to be negotiated by the
                   Parties and the charges will be filed by the
                   Transmission Provider as a supplement to the Service
                   Agreement under this Tariff.  
              7.6  Changes in Service Requests:  Under no circumstances
                   shall a Transmission Customer's decision to cancel or
                   delay the addition of a new Network Resource and/or
                   designation of a new Member System in any way reduce or
                   relieve the Transmission Customer's obligation to pay
                   the costs of transmission facilities constructed by the
                   Transmission Provider and charged to the Transmission
                   Customer as reflected in the Service Agreement;
                   however, upon receipt of a Transmission Customer's
                   written notice of such a cancellation or delay, the
                   Transmission Provider will use the same reasonable
                   efforts to mitigate the costs and charges owed to the
                   Transmission Provider as it would to reduce its own
                   costs and charges.  
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              7.7  Annual Load and Resource Information Updates:  A
                   Transmission Customer shall provide the Transmission
                   Provider with annual updates of Network Load and
                   Network Resource forecasts consistent with those
                   included in its Application for Network Integration
                   Service under this Tariff.  The Transmission Customer
                   also shall provide the Transmission Provider with
                   timely written notice of material changes in any other
                   information provided in its Application relating to the
                   Transmission Customer's Network Load, Network
                   Resources, its transmission system or other aspects of
                   its facilities or operations affecting the Transmission
                   Provider's ability to provide reliable service under
                   this Tariff.
         8.0.  Ancillary Services
              Ancillary services include all services necessary to support
         the transmission of electric power from resources to load while
         maintaining reliable operation of the interconnected transmission
         system.  A Transmission Customer may purchase the ancillary
         services necessary for prudent utility operation from the
         Transmission Provider or from another supplier where the purchase
         is consistent with Good Utility Practice and technically
         feasible.  To the extent that the Transmission Provider provides
         itself with any ancillary services, or is capable of providing
         itself with any ancillary services, the Transmission Provider
         will be required to offer similar services to the Transmission
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         Customer pursuant to Good Utility Practice.  The specific
         ancillary services, prices and/or compensation methods are
         described on the attached schedules.  Sections 8.1 through 8.6
         below, list examples of possible ancillary services.  The
         Transmission Provider shall list all of the Ancillary Services it
         is capable of providing and appropriate Schedules for such
         services.
              8.1  Loss Compensation Service:  Where applicable the rates
                   and/or methodology are described in Schedule 2.
              8.2  Load Following Service:  Where applicable the rates
                   and/or methodology are described in Schedule 3.
              8.3  System Protection Service:  Where applicable the rates
                   and/or methodology are described in Schedule 4.
              8.4  Energy Imbalance Service:  Where applicable the rates
                   and/or methodology are described in Schedule 5.
              8.5  Reactive Power/Voltage Control Service:  Where
                   applicable the rates and/or methodology are described
                   in Schedule 6.
              8.6  Scheduling and Dispatching Service:  Where applicable
                   the rates and/or methodology are described in
                   Schedule 7.
         9.0.  Load Shedding and Curtailments
              9.1  Procedures:  Prior to the commencement of service
                   hereunder, the Transmission Provider and the
                   Transmission Customer shall establish emergency load
                   shedding and curtailment procedures with the objective
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                   of responding to emergencies on the Transmission
                   System.  The parties will implement such programs
                   during any period when the Transmission Provider
                   determines that a transmission capacity constraint
                   exists and such procedures are necessary to alleviate
                   such constraint.  The Transmission Provider will notify
                   all affected Transmission Customers in a timely manner
                   of any scheduled interruption (e.g., scheduled
                   maintenance).  
              9.2  Transmission Constraints:  During any period when the
                   Transmission Provider determines that a transmission
                   constraint exists on the Transmission System, and such
                   constraint may impair the reliability of the
                   Transmission Provider system or adversely affect the
                   economic operations of either the Transmission Provider
                   or a Transmission Customer, the Transmission Provider
                   will take whatever actions, consistent with Good
                   Utility Practice, that are reasonably necessary to
                   maintain the reliability of the Transmission Provider's
                   system and avoid interruption of service.  To the
                   extent the Transmission Provider determines that the
                   reliability of the Transmission System can be
                   maintained by redispatching resources (including
                   reductions in off-system purchases and sales), the
                   Transmission Provider will initiate procedures pursuant
                   to the Network Operating Agreement to redispatch the
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                   Transmission Provider's and/or Transmission Customers'
                   resources on a least-cost basis without regard to the
                   ownership of such resources.  Any redispatch under this
                   Section will not be unduly discriminatory as between
                   the Transmission Provider and other Network Integration
                   Service Transmission Customers.  
              9.3  Cost Responsibility for Relieving Capacity Constraints:
                   Whenever the Transmission Provider implements least-
                   cost redispatch procedures, pursuant to Section 9.2, to
                   relieve a capacity constraint, the Transmission
                   Provider and Transmission Customer will determine the
                   total cost impact of such procedures.  The Transmission
                   Provider and Transmission Customer will each bear a
                   proportionate share of the total redispatch cost impact
                   based on the then-current Load Ratio Shares.
              9.4  Curtailments of Scheduled Deliveries:  To the extent
                   that a transmission constraint on the Transmission
                   Provider's Transmission System cannot be relieved
                   through the implementation of least-cost redispatch
                   procedures and the Transmission Provider determines
                   that it is necessary for the Transmission Provider and
                   the Transmission Customer to curtail scheduled
                   deliveries, the Parties shall curtail such schedules in
                   accordance with previously established curtailment
                   procedures.
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              9.5  Allocation of Curtailments:  To the extent practicable
                   and consistent with Good Utility Practice, any
                   scheduling curtailment will be shared by the
                   Transmission Provider and Transmission Customer in
                   proportion to the then-current Load Ratio Shares.  The
                   Transmission Provider shall not direct the Transmission
                   Customer to curtail schedules to an extent greater than
                   the Transmission Provider would curtail the
                   Transmission Provider's schedules under similar
                   circumstances.  
              9.6  Load Shedding:  To the extent that a transmission
                   constraint exists on the Transmission Provider's
                   Transmission System and the Transmission Provider
                   determines that it is necessary for the Transmission
                   Provider and the Transmission Customer to shed load,
                   the parties shall shed load in accordance with
                   previously established load shedding procedures under
                   the Network Operating Agreement.
              9.7  System Reliability:  Notwithstanding any other
                   provisions of this Agreement, the Transmission Provider
                   reserves the right, consistent with Good Utility
                   Practice and on a not unduly discriminatory basis, to
                   interrupt Network Integration Service without liability
                   on the Transmission Provider's part for the purpose of
                   making necessary adjustments to, changes in, or repairs
                   on its lines, substations and facilities, and in cases
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                   where the continuance of Network Integration Service
                   would endanger persons or property.  In the event of
                   any adverse condition(s) or disturbance(s) on the
                   Transmission Provider's system or on any other
                   system(s) directly or indirectly interconnected with
                   the Transmission Provider's system, the Transmission
                   Provider, consistent with Good Utility Practice, also
                   may interrupt Network Integration Service in order to
                   (i) limit the extent or damage of the adverse
                   condition(s) or disturbance(s), (ii) prevent damage to
                   generating or transmission facilities, or (iii)
                   expedite restoration of service.  The Transmission
                   Provider will give the Transmission Customer as much
                   advance notice as is practicable in the event of such
                   interruption.  Any interruption of Network Integration
                   Service will be not unduly discriminatory relative to
                   the Transmission Provider's use of the Transmission
                   System on behalf of its Native Load Customers.  The
                   Transmission Customer's failure to respond to
                   established emergency load shedding and curtailment
                   procedures to relieve emergencies on the transmission
                   system may be deemed by the Transmission Provider to be
                   a default under this Tariff, and the Transmission
                   Provider may seek termination of this Tariff subject to
                   applicable Commission Policy.
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         10.0  Off-System and Third-Party Sales
              No service provided under this Tariff shall be used by a
         Transmission Customer for off-system or third party sales of
         capacity and/or energy.  A Transmission Customer shall be
         required to purchase transmission service separately under the
         Transmission Provider's Point-to-Point Transmission Service
         Tariff for any off-system or third-party sales.  The Transmission
         Provider shall use its Point-to-Point Transmission Service Tariff
         to make its own off-system or third-party sales.
         11.0  Rates and Charges
            11.1   Monthly Demand Charge:  A Transmission Customer shall
                   pay a monthly Demand Charge, which shall be determined
                   by multiplying its Load Ratio Share times one twelfth
                   (1/12) of the Transmission Provider's Annual
                   Transmission Revenue Requirement specified in
                   Schedule 1.
            11.2   Determination of Transmission Customer's Monthly
                   Network Load:  The Transmission Customer's monthly
                   Network Load is the hourly load of the Transmission
                   Customer (including its designated Member Systems
                   included in Network Load in accordance with Section
                   6.3) coincident with the peak load of the Transmission
                   Provider's Transmission System.
            11.3   Determination of Transmission Provider's Total Monthly
                   Load:  The Transmission Provider's monthly Transmission
                   System peak load will consist of the sum of the
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                   coincident peak for service to native load and the
                   coincident demands for all firm transmission services,
                   (for terms of one-year or longer) including the
                   Transmission Provider's off-system sales.
            11.4   Redispatch Charge:  The Transmission Customer shall pay
                   a load-ratio share of any redispatch costs allocated
                   between the Transmission Customer and the Transmission
                   Provider pursuant to Section 9.  To the extent that the
                   Transmission Provider incurs an obligation to the
                   Transmission Customer for redispatch costs in
                   accordance with Section 9, such amounts shall be
                   credited against the Transmission Customer's bill for
                   the month in which such costs are incurred.
            11.5   Stranded Cost Recovery:  The Transmission Provider may
                   seek to recover stranded costs from a Transmission
                   Customer pursuant to this Transmission Tariff in
                   accordance with the terms, conditions and procedures
                   set forth in FERC Order No.      (Final Order on Open
                   Access and Stranded Costs).  However, the Transmission
                   Provider must separately file any specific proposed
                   stranded cost charge under section 205 of the Federal
                   Power Act.
         12.0  Billing and Payment
            12.1   Billing Procedure:  Within a reasonable time after the
                   first day of each month, the Transmission Provider
                   shall submit an invoice to the Transmission Customer
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                   for the charges for all service furnished under this
                   Tariff during the preceding month.  The invoice shall
                   be paid by the Transmission Customer so that the
                   Transmission Provider will receive the funds by the
                   twentieth (20th) day after the date that such invoice
                   is received by the Transmission Customer.  All payments
                   shall be made in immediately available funds payable to
                   Transmission Provider, or by wire transfer to a bank
                   named by the Transmission Provider.
            12.2   Interest on Unpaid Balances:  Interest on any unpaid
                   amount shall be calculated in accordance with the
                   methodology specified for interest on refunds in the
                   Commission's regulations at 18 C.F.R. §
                   35.19a(a)(2)(iii).  Interest on delinquent amounts
                   shall be calculated from the due date of the bill to
                   the date of payment.  When payments are made by mail,
                   bills shall be considered as having been paid on the
                   date of receipt by the Transmission Provider.
            12.3   Customer Default:  In the event the Transmission
                   Customer fails, for any reason other than a billing
                   dispute as described below, to make payment to the
                   Transmission Provider on or before the due date as
                   described above, and such failure of payment is not
                   corrected within thirty (30) calendar days after the
                   Transmission Provider notifies the Transmission
                   Customer to cure such failure, a default by the
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                   Transmission Customer shall be deemed to exist.  Upon
                   the occurrence of a default, the Transmission Provider
                   may initiate a proceeding with the Commission to
                   terminate service but shall not terminate service until
                   the Commission approves any such request.  In the event
                   of a billing dispute between the Transmission Provider
                   and the Transmission Customer, the Transmission
                   Provider will continue to provide service as long as
                   the Transmission Customer (i) continues to make all
                   payments not in dispute and (ii) pays into an
                   independent escrow account the portion of the invoice
                   in dispute, pending resolution of such dispute.  If the
                   Transmission Customer fails to meet these two
                   requirements for continuation of service, then the
                   Transmission Provider will provide notice to the
                   Transmission Customer and to the Commission of its
                   intention to terminate service pursuant to a filing
                   under section 35.15 of the regulations in accordance
                   with Commission policy.
         13.0  Booking of Costs Attributable to The Transmission
               Provider's Use of this Tariff.
              The Transmission Provider shall book into separate accounts,
         as outlined below, the following amounts:
                   (a)  Impact Study Costs - the cost to perform any
                        System Impact Studies or Facilities Studies that
                        the Transmission Provider undertakes to determine
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                        if the Transmission Provider must construct new
                        transmission facilities or upgrades necessary for
                        the Transmission Provider to provide new
                        transmission service for its native load under
                        this Tariff; and,
                   (b)  Cost Responsibility for Relieving Capacity
                        Constraints - the Transmission Provider's
                        proportionate share of the total redispatch costs
                        to relieve capacity constraints on the system, as
                        provided in Section 9.
         14.0  Standards of Conduct
              In implementing the provisions of this Tariff, the Parties
         shall comply with the following standards of conduct:
            14.1   Standard of Nondiscrimination:  In performing its
                   obligations under this Tariff, the Transmission
                   Provider shall apply the Tariff's provisions in a non-
                   discriminatory manner to all users, including the
                   Transmission Provider's use of this Tariff.
            14.2   Communications with Eligible Customers:  The
                   Transmission Provider shall use all reasonable efforts
                   to communicate promptly with all Eligible Customers to
                   resolve any questions regarding their requests for
                   service and in a non-discriminatory manner.   
            14.3   Standard of Due Diligence:  Where the Transmission
                   Provider or the Transmission Customer is required to
                   complete activities or to negotiate agreements as a
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                                                     Original Sheet No. 39
                   condition of service under this Tariff, each party
                   shall use due diligence to complete these actions
                   within a reasonable time.    
            14.4   Dispute Resolution Procedures:  If any Transmission
                   Customer has a dispute or complaint that relates to the
                   conduct of the Transmission Provider under this Tariff,
                   the Transmission Customer may use the dispute
                   resolution procedures provided in Section 19.
         15.0  Indemnification and Liability
               Neither the Transmission Customer nor the Transmission
         Provider shall be liable to the other for damages for any act,
         omission, or circumstance occasioned by or in consequence of any
         act of God, labor disturbance, act of the public enemy, war,
         insurrection, riot, fire, storm or flood, explosion, breakage or
         accident to machinery or equipment, or by any other cause or
         causes beyond such party's control, including any curtailment,
         order, regulation or restriction imposed by governmental military
         or lawfully established civilian authorities, or by the making of
         necessary repairs upon the property or equipment of either party
         hereto.
              Notwithstanding the provisions of the foregoing paragraph,
         the Transmission Customer and the Transmission Provider shall at
         all times assume all liability for, and shall indemnify and save
         each other harmless from, any and all damages, losses, claims,
         demands, suits, recoveries, costs and expenses, including all
         court costs and attorney fees, arising out of or resulting from,
                                               Network Transmission Tariff
                                                     Original Sheet No. 40
         either directly or indirectly, their respective facilities, or
         the electric capacity and/or energy transmitted hereunder whether
         such damages, losses, claims, demands, suits, recoveries, costs
         and expenses result from any injury to or death of any person or
         persons whomsoever, or from any loss, destruction of or damage to
         any property of any third party, or from any outages, or from any
         business interruption, or from any other cause whatsoever,
         occurring on their respective systems, or on the system(s) of
         parties served by the Transmission Customer or the Transmission
         Provider, or the Parties purchasing or transmitting the capacity
         and/or energy received or delivered by the Transmission Provider
         or the Transmission Customer pursuant to the Service Agreement,
         except in cases of gross negligence or intentional wrongdoing.
         16.0  Regulatory Filings
              Nothing contained in this Tariff or any Service Agreement
         shall be construed as affecting in any way the right of the
         Transmission Provider to unilaterally make application to the
         Commission for a change in rates, charges, classification of
         service, or any rule, regulation, or Service Agreement related
         thereto, under Section 205 of the Federal Power Act and pursuant
         to the Commission's rules and regulations promulgated thereunder.
              Nothing contained in this Tariff or any associated Service
         Agreement shall be construed as affecting in any way the ability
         of any Transmission Customer receiving Network Integration
         Service under the Tariff to exercise its rights under the Federal
                                               Network Transmission Tariff
                                                     Original Sheet No. 41
         Power Act and pursuant to the Commission's rules and regulations
         promulgated thereunder.
         17.0  Operating Arrangements
            17.1   Operation Under The Network Operating Agreement:  A
                   Transmission Customer shall plan, construct, operate
                   and maintain its facilities in accordance with Good
                   Utility Practice, which shall include, but not be
                   limited to, all applicable NERC and regional
                   reliability council guidelines, or any generally
                   accepted practices in the region that are consistently
                   adhered to by the Transmission Provider as well as
                   conformance with the Network Operating Agreement.  
            17.2   Network Operating Agreement: The terms and conditions
                   under which the Transmission Customer shall operate its
                   facilities and the technical and operational matters
                   associated with the implementation of this Tariff shall
                   be specified in a separate Network Operating Agreement.
                   The Network Operating Agreement shall provide for the
                   Parties to: (i) operate and maintain equipment
                   necessary for incorporating the Transmission Customer
                   within the Transmission Provider's transmission system
                   (including, but not limited to, remote terminal units,
                   metering, communications equipment and relaying
                   equipment); (ii) transfer data between the Transmission
                   Provider and the Transmission Customer's control
                   centers (including, but not limited to, heat rates and
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                                                     Original Sheet No. 42
                   operational characteristics of Network Resources,
                   generation schedules for units outside the Transmission
                   Provider's transmission system, interchange schedules,
                   unit outputs for redispatch required under Section 9,
                   voltage schedules, loss factors and other real time
                   data); (iii) use software programs required for data
                   links and constraint dispatching; (iv) exchange data on
                   forecasted loads and resources necessary for long-term
                   planning; and (v) address any other technical and
                   operational considerations required for implementation
                   of this Tariff, including scheduling protocols.  A
                   Network Operating Agreement is provided in Appendix C.
         18.0  Network Operating Committee
              A Network Operating Committee (Committee) shall be
         established to coordinate operating criteria for the parties'
         respective responsibilities under this Tariff including:  (i)
         standards for the design, operation and maintenance of the
         facilities necessary to integrate Transmission Customer Electric
         Systems with the Transmission Provider's Transmission System
         (including, but not limited to, remote terminal units, metering,
         communications equipment and relaying equipment); (ii)
         information transfers between control centers (including, but not
         limited to, operational characteristics of Network Resources,
         generation schedules for units outside the Transmission
         Provider's Transmission System, interchange schedules, unit
         outputs for dispatch, voltage schedules, loss factors and other
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                                                     Original Sheet No. 43
         real-time data); (iii) software programs required for data links
         and constraint dispatching; (iv) information required for long-
         term planning; (v) load curtailment procedures in the event of
         transmission constraints or system emergencies; (vi) least-cost
         redispatch procedures; and (vii) other technical and operational
         considerations required for implementation of this Tariff.  Each
         customer and the Transmission Provider shall have at least one
         representative on the Committee.  The Committee shall meet from
         time to time as need requires, but no less than once each
         calendar year.
         19.0  Resolution of Disputes
            19.1   Internal Dispute Resolution Procedures:  Any dispute
                   between a Transmission Customer and the Transmission
                   Provider involving Network Integration Service under
                   this Tariff (excluding applications for rate changes or
                   other changes to this Tariff, or to any Service
                   Agreement entered into under this Tariff, which shall
                   be presented directly to the Commission for resolution)
                   shall be referred to a designated senior representative
                   of the Transmission Provider and a senior
                   representative of the Transmission Customer for
                   resolution on an informal basis as promptly as
                   practicable.  If mutually agreeable, in the event the
                   designated representatives are unable to resolve the
                   dispute within thirty (30) days, or such other period
                   as the parties may mutually agree upon, such dispute
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                                                     Original Sheet No. 44
                   shall be submitted to arbitration and resolved in
                   accordance with the arbitration procedures set forth
                   below.      
            19.2   External Arbitration Procedures:  Any arbitration
                   initiated under this Tariff shall be conducted before a
                   single neutral arbitrator appointed by the parties.  If
                   the parties fail to agree upon a single arbitrator
                   within ten (10) days of the referral of the dispute to
                   arbitration, each party shall choose one arbitrator who
                   shall sit on a three-member arbitration panel.  The two
                   arbitrators so chosen shall within twenty (20) days
                   select a third arbitrator to chair the arbitration
                   panel.  In either case, the arbitrators shall be
                   knowledgeable in electric utility matters, including
                   electricity transmission and bulk power issues, and
                   shall not have any current or past substantial business
                   or financial relationships with any party to the
                   arbitration (other than previous arbitration
                   experience).  The arbitrator(s) shall provide each of
                   the parties an opportunity to be heard and, except as
                   otherwise provided herein, shall generally conduct the
                   arbitration in accordance with the Commercial
                   Arbitration Rules of the American Arbitration
                   Association and any applicable Commission or Regional
                   Transmission Group rules.
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                                                     Original Sheet No. 45
            19.3   Arbitration Decisions:  Unless otherwise agreed, the
                   arbitrator(s) shall render a decision within ninety
                   (90) days of appointment and shall notify the parties
                   in writing of such decision and the reasons therefor.
                   The arbitrator(s) shall be authorized only to interpret
                   and apply the provisions of this Tariff and any Service
                   Agreement entered into under this Tariff and shall have
                   no power to modify or change any of the above in any
                   manner.  The decision of the arbitrator(s) shall be
                   final and binding upon the parties, and judgment on the
                   award may be entered in any court having jurisdiction.
                   The decision of the arbitrator(s) may be appealed
                   solely on the grounds that the conduct of the
                   arbitrator(s), or the decision itself, violated the
                   standards set forth in the Federal Arbitration Act
                   and/or the Administrative Dispute Resolution Act.  The
                   final decision of the arbitrator must also be filed
                   with the Commission if it affects jurisdictional rates
                   or facilities.
            19.4   Costs:  Each party shall be responsible for the
                   following costs, if applicable:
                        (i) its own costs incurred during the arbitration
                        process; and
                        (ii) the cost of the arbitrator chosen by the
                        party to sit on the three member panel and one
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                                                     Original Sheet No. 46
                        half of the cost of the third arbitrator chosen;
                        or
                        (iii) one half the cost of the single arbitrator
                        jointly chosen by the parties.  
            19.5   Rights Under The Federal Power Act:  Nothing in this
                   section shall restrict the rights of any party to file
                   a complaint with the Commission under relevant
                   provisions of the Federal Power Act.  In addition, use
                   or application of the arbitration provisions in this
                   Section does not affect the jurisdiction of the
                   Commission over any matters arising under this Tariff.
         20.0  Creditworthiness
              For the purpose of determining the ability of the
         Transmission Customer to meet its obligations related to service
         hereunder, the Transmission Provider may require reasonable
         credit review procedures.  This review shall be made in
         accordance with standard commercial practices.  In addition, the
         Transmission Provider may require the Transmission Customer to
         provide and maintain in effect during the term of the Service
         Agreement, an unconditional and irrevocable letter of credit as
         security to meet its responsibilities and obligations under this
         Tariff, or an alternative form of security proposed by the
         Transmission Customer and acceptable to the Transmission Provider
         and consistent with commercial practices established by the
         Uniform Commercial Code that protects the Transmission Provider
         against the risk of non-payment.  
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                                     Appendix A
                                 STANDARD FORM OF
                                 SERVICE AGREEMENT
         To be filed by the Transmission Provider
                                               Network Transmission Tariff
                                                     Original Sheet No. 48
                                     Appendix B
                           METHODOLOGY FOR COMPLETING A
                                SYSTEM IMPACT STUDY
         To be filed by the Transmission Provider
                                               Network Transmission Tariff
                                                     Original Sheet No. 49
                                     Appendix C
                                 STANDARD FORM OF
                            NETWORK OPERATING AGREEMENT

         To be filed by the Transmission Provider
                                               Network Transmission Tariff
                                                     Original Sheet No. 50
                                     SCHEDULE 1
                      Annual Transmission Revenue Requirement
         1.   The Annual Transmission Revenue Requirement for purposes of
              the Network Integration Service Tariff shall
              be                     .                  
         2.   The amount in (1) shall be effective until amended by the
              Transmission Provider or modified by the Commission.
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                                                     Original Sheet No. 51
                                     SCHEDULE 2
                             Loss Compensation Service
              Capacity and energy losses occur when a Transmission
         Provider delivers electricity across its transmission facilities
         for a Transmission Customer.  A Transmission Customer may elect
         to (1) supply the capacity and/or energy necessary to compensate
         the Transmission Provider for such losses, (2) receive an amount
         of electricity at delivery points that is reduced by the amount
         of losses incurred by the Transmission Provider, or (3) have the
         Transmission Provider supply the capacity and/or energy necessary
         to compensate for such losses.  The procedures to determine the
         amount of losses associated with a transaction are set forth
         below.  If Loss Compensation Service is supplied by the
         Transmission Provider, the applicable charges for such service
         are set forth below.  Both the procedures for determining the
         amount of losses and the charges for loss compensation service
         must be consistent with the rate design of the transmission rates
         charged by the Transmission Provider.  To the extent another
         entity performs this service for the Transmission Provider,
         charges to the Transmission Customer are to reflect only a pass-
         through of the costs charged to the Transmission Provider by that
         entity.
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                                                     Original Sheet No. 52
                                     SCHEDULE 3
                               Load Following Service
              Load Following Service is necessary to provide for the
         continuous balancing of resources (generation and interchange)
         with load under the control of the Transmission Provider (or
         other entity that performs this function for the Transmission
         Provider).  Load Following Service is accomplished by committing
         on-line generation whose output is raised or lowered
         (predominantly through the use of automatic generating control
         equipment) as necessary to follow the moment-by-moment changes in
         load.  The obligation to maintain this balance between resources
         and load lies with the Transmission Provider (or other entity
         that performs this function for the Transmission Provider).
         Because of the nature of this service, the Transmission Provider
         (or other entity that performs this function for the Transmission
         Provider's facilities) may be uniquely positioned to provide Load
         Following Service.  Therefore, unless the Transmission Customer
         is able to obtain such service from its own generation or from
         third party generation that is capable of supplying such service
         in accordance with conditions generally accepted in the region
         and consistently adhered to by the Transmission Provider, the
         Transmission Provider will supply Load Following Service.  The
         charges for Load Following Service are set forth below.  To the
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                                                     Original Sheet No. 53
         extent another entity performs this service for the Transmission
         Provider, charges to the Transmission Customer are to reflect
         only a pass-through of the costs charged to the Transmission
         Provider by that entity.
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                                                     Original Sheet No. 54
                                     SCHEDULE 4
                             System Protection Service
              A Transmission Provider must have adequate operating
         reserves or other system protection facilities available in order
         to maintain the integrity of its transmission facilities in the
         event of (1) unscheduled outages of a portion of its transmission
         facilities or facilities connected to the Transmission Provider's
         service territory or (2) unscheduled interruption of energy
         deliveries to the Transmission Provider's transmission
         facilities.  The amount of System Protection Service that must be
         supplied with respect to the Transmission Customer's transaction
         will be determined based on operating reserve margins or other
         relevant criteria that are generally accepted in the region and
         consistently adhered to by the Transmission Provider.
              The Transmission Customer may elect or arrange through a
         third party to provide resources that are sufficient to satisfy
         the system protection needs of the Transmission Provider.
         Operation and dispatch of such resources must be coordinated with
         the Transmission Provider or other entity that maintains
         operating reserves and other system protection facilities for the
         Transmission Provider's service territory.  Alternatively, if the
         Transmission Customer does not provide System Protection Service,
         the Transmission Provider will provide System Protection Service.
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                                                     Original Sheet No. 55
         The charges for System Protection Service are set forth below.
         To the extent another entity performs this service for the
         Transmission Provider, charges to the Transmission Customer are
         to reflect only a pass-through of the costs charged to the
         Transmission Provider by that entity.
                                               Network Transmission Tariff
                                                     Original Sheet No. 56

                                     SCHEDULE 5
                              Energy Imbalance Service
              Energy Imbalance Service is provided when a difference
         occurs between the hourly scheduled amount and the hourly metered
         (actual delivered) amount associated with a transaction.
         Typically, an energy imbalance is eliminated during a future
         period by returning energy in-kind under conditions similar to
         those when the initial energy was delivered.  
              The Transmission Provider shall establish a deviation band
         (e.g., +/- 1.5 percent of the scheduled transaction) to be
         applied hourly to any energy imbalance that occurs as a result of
         the Transmission Customer's scheduled transaction(s).  Parties
         should attempt to eliminate energy imbalances within the limits
         of the deviation band within 30 days or reasonable period of time
         that is generally accepted in the region and consistently adhered
         to by the Transmission Provider.  If an energy imbalance is not
         corrected within 30 days or a reasonable period of time that is
         generally accepted in the region and consistently adhered to by
         the Transmission Provider, the Transmission Customer will
         compensate the Transmission Provider for such service.  Energy
         imbalances outside the deviation band will be subject to charges
         to be specified by the Transmission Provider.  The charges for
         Energy Imbalance Service are set forth below.  To the extent
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                                                     Original Sheet No. 57
         another entity performs this service for the Transmission
         Provider, charges to the Transmission Customer are to reflect
         only a pass-through of the costs charged to the Transmission
         Provider by that entity.
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                                                     Original Sheet No. 58
                                     SCHEDULE 6
                       Reactive Power/Voltage Control Service
              In order to maintain transmission voltages on the
         Transmission Provider's transmission facilities within acceptable
         limits, transmission facilities and some or all generation
         facilities (in the service area where the Transmission Provider's
         transmission facilities are located) are operated to produce (or
         absorb) reactive power.  Thus, the need for Reactive
         Power/Voltage Control Service must be considered for each
         transaction on the Transmission Provider's transmission
         facilities.  The amount of Reactive Power/Voltage Control Service
         that must be supplied with respect to the Transmission Customer's
         transaction will be determined based on the reactive power
         support necessary to maintain transmission voltages within limits
         that are generally accepted in the region and consistently
         adhered to by the Transmission Provider.
              The Transmission Provider will be responsible for providing
         the necessary transmission-related reactive power support.  A
         Transmission Customer may elect (or arrange through a third
         party) to supply some or all of the necessary generation-related
         reactive power/voltage control support to the extent that it (or
         the third party) has the ability to supply such reactive power.  
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                                                     Original Sheet No. 59
         If the Transmission Customer elects (or arranges through a third
         party) to provide reactive power/voltage control support, such
         service must be coordinated with the Transmission Provider (or
         the entity that is responsible for the operation of the
         Transmission Provider's transmission facilities).  Alternatively,
         the Transmission Provider will supply the necessary generation-
         related reactive power/voltage control support.  The charges for
         such service will be based on the rates set forth below.  To
         avoid double counting in the development of the charge for
         reactive power/voltage control support, the Transmission Provider
         must take into consideration any transmission-related reactive
         power/voltage support charges that are included in the tariff
         transmission rates.  To the extent another entity performs this
         service for the Transmission Provider, charges to the
         Transmission Customer are to reflect only a pass-through of the
         costs charged to the Transmission Provider by that entity.
                                               Network Transmission Tariff
                                                     Original Sheet No. 60
                                     SCHEDULE 7
                         Scheduling and Dispatching Service
              Scheduling is the control room procedure to establish a pre-
         determined (before-the-fact) use of generation resources and
         transmission facilities to meet anticipated load (including
         interchange).  Dispatching is the control room operation of all
         generation resources and transmission facilities on a real-time
         basis to meet load within the Transmission Provider's designated
         service area (or other larger area of coordinated dispatch
         operation).  Scheduling and Dispatching Services are to be
         provided by the Transmission Provider or other entity that
         performs scheduling and dispatching for the Transmission
         Provider's service territory.  The charges for scheduling and
         dispatch services are to be based on the rates set forth below.
         To the extent another entity performs these services for the
         Transmission Provider, charges to the Transmission Customer are
         to reflect only a pass-through of the costs charged to the
         Transmission Provider by that entity.
              In certain regions, dynamic scheduling is also allowed.  In
         these areas the Transmission Customer will be allowed to use
         dynamic scheduling when it is feasible and reliable.  Dynamic
         scheduling involves the arrangement for moving load or generation
         served within one Transmission Provider's service territory (or
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                                                     Original Sheet No. 61
         other larger area of coordinated dispatch operation) such that
         the load or generation is recognized in the real-time control and
         dispatch of another Transmission Provider.  Under dynamic
         scheduling, the operator of an area of coordinated dispatch
         (control area) agrees to assign certain customer load or
         generation to another area of coordinated dispatch, and to send
         the associated control signals to the respective control center
         of that area.  Dynamic scheduling is implemented through the use
         of specific telemetry and control equipment.  If the Transmission
         Provider supplies dynamic scheduling service to the Transmission
         Customer, the charges will be based on rates set forth below.  
                                               Network Transmission Tariff
                                                     Original Sheet No. 62
           INDEX OF CUSTOMERS UNDER FERC NETWORK INTEGRATION TRANSMISSION
                                   SERVICE TARIFF
                                                        Date of
                        Customer                        Service Agreement
                                     APPENDIX D
                               Docket No. RM94-7-000
                   RECOVERY OF STRANDED COSTS BY PUBLIC UTILITIES
                             AND TRANSMITTING UTILITIES
                                 LIST OF COMMENTERS
         1.   Ad Hoc Coalition on Environmental and Consumer Protection
                (Ad Hoc Coalition), consisting of Environmental Action
                Foundation, Citizen Action, Consumer Federation of
                America, Greenpeace, Toward Utility Rate Normalization,
                Public Citizen, Sierra Club, Nuclear Information &
                Resource Service, Economic Opportunity Research Institute,
                and U.S. Public Interest Research Group
         2.   Alabama Public Service Commission
         3.   Allegheny Electric Cooperative, Inc.
         4.   Allegheny Power Service Corporation (Allegheny Power)
         5.   American Forest & Paper Association (American Forest)
         6.   American Public Power Association (APPA)
         7.   American Society of Utility Investors
         8.   Arizona Public Service Company
         9.   Arkansas Public Service Commission
         10.  Atlantic City Electric Company
         11.  Blue Ridge Power Agency, Northeast Texas Electric
                Cooperative, Sam Rayburn G&T Electric Cooperative and
                Tex-La Electric Cooperative (Blue Ridge)
         12.  California Public Utilities Commission
         13.  Centerior Energy Corporation
         14.  Central Maine Power Company
         15.  Central Vermont Public Service Corporation
         16.  Cities of Anaheim, Azusa, Banning, Colton and Riverside,
                California
         17.  City of Las Cruces, New Mexico
         Docket No. RM94-7-000          -2-
         18.  Coalition For Economic Competition, consisting of Central
                Hudson Gas & Electric Corporation, Consolidated Edison
                Company of New York, Long Island Lighting Company, New
                York State Electric & Gas Corporation, Niagara Mohawk
                Power Corporation, and Rochester Gas & Electric Company
         19.  Coalition of California Utility Employees
         20.  Colorado Association of Municipal Utilities
         21.  Colorado Office of Consumer Counsel
         22.  Colorado Public Utilities Commission
         23.  Commonwealth Edison Company (Commonwealth Edison)
         24.  Competitive Electric Market Working Group (Competitive
                Working Group), consisting of Electric Clearinghouse,
                Inc., Enron Power Marketing, Inc., and Destec Power   
                Services, Inc.
         25.  Conservation Law Foundation
         26.  Consumer-Owned Utilities in Maine, consisting of Eastern
                Maine Electric Cooperative, Inc., Fox Islands Electric
                Cooperative, Inc., Houlton Water Company, Isle au Haut
                Electric Power Co., Kennebunk Light & Power District,
                Madison Electric Works, Swans Island Electric Cooperative,
                Inc., Union River Electric Cooperative, Inc., and Van
                Buren Light & Power District
         27.  Consumers Power Company
         28.  Dairyland Power Cooperative
         29.  Department of Water and Power of the City of Los Angeles
         30.  Detroit Edison Company (Detroit Edison)
         31.  Direct Action For Rights and Equality
         32.  District of Columbia Public Service Commission
         33.  Duke Power Company
         34.  Duquesne Light Company
         35.  Edison Electric Institute (EEI)
         36.  Electric Consumers' Alliance
         37.  Electric Generation Association
         Docket No. RM94-7-000          -3-
         38.  Electricity Consumers Resource Council, the American Iron
                and Steel Institute and the Chemical Manufacturers
                Association (Industrial Consumers)
         39.  El Paso Electric Company
         40.  Enron Power Marketing, Inc. (Enron)
         41.  Entergy Services, Inc. (Entergy)
         42.  Environmental Action Foundation (Environmental Action)
         43.  Environmental Law and Policy Center of the Midwest
         44.  Florida Municipal Power Agency, Michigan Municipal
                Cooperative Group and Wolverine Power Supply Cooperative
                (Florida and Michigan Municipals)
         45.  Florida Power Corporation
         46.  Florida Public Service Commission (Florida Commission)
         47.  Fuel Managers Association
         48.  Houston Lighting & Power Company (Houston Lighting & Power)
         49.  Idaho Public Utilities Commission
         50.  Illinois Commerce Commission (Illinois Commission)
         51.  Illinois Power Company
         52.  Indiana Office of Utility Consumer Counselor
         53.  Indiana Utility Regulatory Commission (Indiana Commission)
         54.  Iowa Utilities Board
         55.  Irrigation and Electrical Districts' Association of Arizona
         56.  Land and Water Fund of the Rockies
         57.  Large Public Power Council
         58.  Long Island Lighting Company (Long Island Lighting)
         59.  Louisiana Energy and Power Authority
         60.  Maryland Public Service Commission
         61.  Massachusetts Department of Public Utilities
         Docket No. RM94-7-000          -4-
         62.  Metropolitan Edison Company, Pennsylvania Electric Company
                and Jersey Central Power & Light Company
         63.  Michigan Public Service Commission Staff
         64.  Mid-Atlantic Energy Project
         65.  Municipal Resale Service Customers of Ohio Power Company
         66.  National Association of Regulatory Utility Commissioners
                (NARUC)
         67.  National Association of State Utility Consumer Advocates
                (NASUCA)
         68.  National Black Caucus of State Legislators
         69.  National Independent Energy Producers (NIEP)
         70.  National Rural Electric Cooperative Association
         71.  New England Power Company
         72.  New York Mercantile Exchange
         73.  New York State Electric & Gas Corporation
         74.  New York State Public Service Commission (New York
                Commission)
         75.  North Carolina Electric Membership Corporation
         76.  North Dakota Public Service Commission
         77.  Northern States Power Company
         78.  Nuclear Energy Institute
         79.  Oglethorpe Power Corporation
         80.  Ohio Office of the Consumers' Counsel
         81.  Ohio Public Utilities Commission (Ohio Commission)
         82.  Older Women's League
         83.  Omaha Public Power District
         84.  Pace Energy Project
         85.  Pacific Gas and Electric Company
         Docket No. RM94-7-000          -5-
         86.  Pacific Gas and Electric Company and Natural Resources
                Defense Council
         87.  PECO Energy Company
         88.  Pennsylvania and Massachusetts Municipals
         89.  Pennsylvania Power & Light Company
         90.  Pennsylvania Public Utility Commission (Pennsylvania
                Commission)
         91.  Public Power Council
         92.  Public Service Company of New Mexico
         93.  Public Service Electric and Gas Company (Public Service
                Electric)
         94.  Rhode Island Division of Public Utilities and Carriers and
                Jeffrey B. Pine, Attorney General of the State of Rhode
                Island
         95.  Rural Utilities Service
         96.  Sacramento Municipal Utility District
         97.  San Diego Gas & Electric Company
         98.  Sierra Pacific Power Company
         99.  South Carolina Electric & Gas Company
         100. Southern California Edison Company
         101. Southern Company Services, Inc.
         102. Stranded Cost Order Opponent Parties, consisting of the
                Delaware Municipal Electric Corporation, Village of
                Freeport, New York, City of Jamestown, New York, Town of
                Massena, New York, Modesto Irrigation District, M-S-R
                Public Power Agency, City of Santa Clara, California, and
                Southern Maryland Electric Cooperative, Inc. (SCOOP)
         103. Suffolk County Electrical Agency

         104. Sunflower Electric Power Corporation (Sunflower)
         105. Tampa Electric Company
         106. Tennessee Valley Authority (TVA)
         Docket No. RM94-7-000          -6-
         107. Public Utility Commission of Texas (Texas Commission)
         108. Texas Utilities Electric Company
         109. Transmission Access Policy Study Group (TAPS)
         110. TDU Customers, consisting of Chicopee Municipal Lighting
                Plant of the City of Chicopee, Massachusetts, Golden
                Spread Electric Cooperative, Inc., Holy Cross Electric
                Association, Inc., Kansas Electric Power Cooperative,
                Inc., Old Dominion Electric Cooperative, Seminole Electric
                Cooperative, Inc., South Hadley Electric Light Department
                of the Town of South Hadley, Massachusetts, and Westfield
                Gas and Electric Department of the City of Westfield,
                Massachusetts
         111. Trigen Energy Corporation
         112. United Illuminating Company
         113. United States Department of Defense
         114. United States Department of Energy (DOE)
         115. United Utility Shareholders Association of America
         116. Utility Investors and Analysts
         117. Utility Working Group (consisting of Dominion Resources,
                Inc., Duke Power Company, Duquesne Light Company, Entergy
                Corporation, General Public Utilities Corporation, Niagara
                Mohawk Power Corporation, Northern States Power Company,
                Pacific Gas and Electric Company, Portland General
                Electric Company, Public Service Electric and Gas Company,
                San Diego Gas & Electric Company, Southern California
                Edison Company, and Wisconsin Electric Power Company)
         118. Vermont Department of Public Service (Vermont Department)
         119. Virginia Electric and Power Company
         120. Virginia State Corporation Commission
         121. Washington Utilities and Transportation Commission
         122. Washington Water Power Company
         123. Wheeled Electric Power Company
         124. Wisconsin Electric Power Company
         125. Wisconsin Power & Light Company (Wisconsin Power)
         Docket No. RM94-7-000          -7-
         126. Wisconsin Public Service Commission
         127. Wisconsin Wholesale Customers
         128. Wyoming Public Service Commission
                              UNITED STATES OF AMERICA
                        FEDERAL ENERGY REGULATORY COMMISSION
                              18 CFR Parts 141 and 388
                              [Docket No. RM95-9-000]
                           Real-Time Information Networks
              NOTICE OF TECHNICAL CONFERENCE AND REQUEST FOR COMMENTS
                                  (March 29, 1995)
         AGENCY:  Federal Energy Regulatory Commission.
         ACTION:  Notice of Technical Conference and Request for Comments.
         SUMMARY:  The Federal Energy Regulatory Commission (Commission),
         is issuing this notice to announce a technical conference to be
         scheduled at a later date, and, in preparation for that
         conference, to request comments on:  (1) whether real-time
         information networks (RINs) or some other option is the best
         method to ensure that potential purchasers of transmission
         services receive access to information to enable them to obtain
         open access transmission service on a non-discriminatory basis
         from public utilities that own and/or control facilities used for
         the transmission of electric energy in interstate commerce; and
         (2) what standards should be adopted if the Commission requires
         such public utilities to institute RINs systems.
         DATES:  Parties wishing to file comments must file an original
         and 14 copies of their comments.  In addition, commenters are
         requested to submit a copy of their comments on a 3½ inch
         diskette, formatted for MS-DOS based computers.  In light of our
         ability to translate MS-DOS based materials, the text need only
         be submitted in the format and version in which it was generated
         (i.e., MS Word, Wordperfect, ASCII, etc.).  It is not necessary
         Docket No. RM95-9-000            - 2 -
         to reformat word processor generated text to ASCII.  For
         Macintosh users, it would be helpful to save the documents in
         Macintosh word processor format and then write them to files on a
         diskette formatted for MS-DOS machines.  Comments must be
         received on or before [insert date that is 60 days after this
         notice is published in the Federal Register].  
         ADDRESSES:
         Send comments to:
              Office of the Secretary
              Federal Energy Regulatory Commission
              825 North Capitol Street, N.E.
              Washington, D.C.  20426
         FOR FURTHER INFORMATION CONTACT:
              Gary D. Cohen (Legal Information)
              Electric Rates and Corporate Regulation
              Office of the General Counsel
              Federal Energy Regulatory Commission
              825 North Capitol Street, N.E.
              Washington, D.C.  20426
              [phone]
              Marvin Rosenberg (Technical Information)
              Office of Economic Policy
              Federal Energy Regulatory Commission
              825 North Capitol Street, N.E.
              Washington, D.C.  20426
              [phone]
         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, N.E., Washington, D.C.
         20426.
         Docket No. RM95-9-000            - 3 -
              The Commission Issuance Posting System (CIPS), an electronic
         bulletin board service, provides access to the text 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 [phone].  To access CIPS, set your
         communications software to 19200, 14400, 12000, 9600, 7200, 4800,
         2400, 1200, or 300 bps, full duplex, no parity, 8 data bits and 1
         stop bit.  The full text of this document will be available on
         CIPS for 60 days from the date of issuance in ASCII and
         Wordperfect 5.1 format.  After 60 days, the document will be
         archived, but still accessible.  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, N.E., Washington, D.C.
         20426.
                              UNITED STATES OF AMERICA
                        FEDERAL ENERGY REGULATORY COMMISSION
                              18 CFR Parts 141 and 388
                              [Docket No. RM95-9-000]
                           Real-Time Information Networks
              NOTICE OF TECHNICAL CONFERENCE AND REQUEST FOR COMMENTS
                                  (March 29, 1995)
         AGENCY:  Federal Energy Regulatory Commission.
         ACTION:  Notice of Technical Conference and Request for Comments.
         SUMMARY:  The Federal Energy Regulatory Commission (Commission),
         is issuing this notice to announce a technical conference to be
         scheduled at a later date, and, in preparation for that
         conference, to request comments on:  (1) whether real-time
         information networks (RINs) or some other option is the best
         method to ensure that potential purchasers of transmission
         services receive access to information to enable them to obtain
         open access transmission service on a non-discriminatory basis
         from public utilities that own and/or control facilities used for
         the transmission of electric energy in interstate commerce; and
         (2) what standards should be adopted if the Commission requires
         such public utilities to institute RINs systems.
         DATES:  Parties wishing to file comments must file an original
         and 14 copies of their comments.  In addition, commenters are
         requested to submit a copy of their comments on a 3½ inch
         diskette, formatted for MS-DOS based computers.  In light of our
         ability to translate MS-DOS based materials, the text need only
         be submitted in the format and version in which it was generated
         (i.e., MS Word, Wordperfect, ASCII, etc.).  It is not necessary
         Docket No. RM95-9-000            - 2 -
         to reformat word processor generated text to ASCII.  For
         Macintosh users, it would be helpful to save the documents in
         Macintosh word processor format and then write them to files on a
         diskette formatted for MS-DOS machines.  Comments must be
         received on or before [insert date that is 60 days after this
         notice is published in the Federal Register].  
         ADDRESSES:
         Send comments to:
              Office of the Secretary
              Federal Energy Regulatory Commission
              825 North Capitol Street, N.E.
              Washington, D.C.  20426
         FOR FURTHER INFORMATION CONTACT:
              Gary D. Cohen (Legal Information)
              Electric Rates and Corporate Regulation
              Office of the General Counsel
              Federal Energy Regulatory Commission
              825 North Capitol Street, N.E.
              Washington, D.C.  20426
              [phone]
              Marvin Rosenberg (Technical Information)
              Office of Economic Policy
              Federal Energy Regulatory Commission
              825 North Capitol Street, N.E.
              Washington, D.C.  20426
              [phone]
         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, N.E., Washington, D.C.
         20426.
         Docket No. RM95-9-000            - 3 -
              The Commission Issuance Posting System (CIPS), an electronic
         bulletin board service, provides access to the text 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 [phone].  To access CIPS, set your
         communications software to 19200, 14400, 12000, 9600, 7200, 4800,
         2400, 1200, or 300 bps, full duplex, no parity, 8 data bits and 1
         stop bit.  The full text of this document will be available on
         CIPS for 60 days from the date of issuance in ASCII and
         Wordperfect 5.1 format.  After 60 days, the document will be
         archived, but still accessible.  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, N.E., Washington, D.C.
         20426.
                              UNITED STATES OF AMERICA
                        FEDERAL ENERGY REGULATORY COMMISSION
         Real-time Information          )            Docket No. RM95-9-000
            Networks                    )
              NOTICE OF TECHNICAL CONFERENCE AND REQUEST FOR COMMENTS
                                  (March 29, 1995)
         INTRODUCTION
              The Commission is considering requiring each public utility
         (or its agent) that owns and/or controls facilities used for the
         transmission of electric energy in interstate commerce to create
         a real-time information network (RIN) to ensure that potential
         purchasers of transmission services have access to information to
         enable them to obtain open access transmission services on a non-
         discriminatory basis from the public utility.  This initiative is
         being taken in conjunction with the Commission's proposed rules,
         1/ today being issued, that would require public utilities to
         provide open access non-discriminatory transmission services
         (Open Access NOPR) and would permit the recovery of legitimate
         and verifiable stranded costs in certain circumstances.
              The Commission's goal in this proceeding is to establish
         uniform requirements for a RIN or other communications device at
         the same time that the Commission adopts a rule requiring open

         1/   See Promoting Wholesale Competition Through Open Access Non-
              discriminatory Transmission Services by Public Utilities &
              Recovery of Stranded Costs by Public Utilities and
              Transmitting Utilities, Notice of Proposed Rulemaking,
              Docket Nos. RM95-8-000 & RM94-7-001 (1995).
         Docket No. RM95-9-000            - 2 -
         access non-discriminatory transmission services.  To accomplish
         this objective, the Commission invites interested persons to file
         comments and to participate in a Technical Conference in which
         they can make presentations on their positions.  Thereafter, the
         Commission expects to hold informal conferences, enlisting
         working groups to reach consensus on any remaining issues.
              We expect that input from the Technical Conference and
         informal conferences will be the basis for subsequent procedures.
         This notice sets a timetable to be followed so that requirements
         on RINS can be in place no later than the effective date of an
         open access rule.
         BACKGROUND
              In the Open Access NOPR, the Commission is inviting comments
         on a proposed rule that would require any public utility that
         owns and/or controls facilities used for the transmission of
         electric energy in interstate commerce to have on file an open
         access transmission tariff.
              To be effective, however, non-discriminatory open access
         transmission service requires transmission customers to be able
         to compete effectively with the public utility that owns or
         controls the transmission.  Customers must have simultaneous
         access to the same information available to the transmission
         owner.  Thus, in this proceeding, the Commission expects to
         require RINs or other options to ensure that potential and actual
         transmission service customers receive access to information so
         Docket No. RM95-9-000            - 3 -
         that they can obtain service comparable to that provided by
         transmission owners (or controllers) to themselves.
         DISCUSSION
         A.   Objectives
              As noted above, the Commission expects to undertake further
         procedures in this docket after the Technical Conference and
         informal conferences are held and input from those conferences is
         evaluated.  Nevertheless, to help participants focus on the
         issues, the Commission here sets out its preliminary views.  Any
         requirement we establish must have safeguards to ensure that
         public utilities owning and/or controlling transmission
         facilities use the same procedures and meet the same substantive
         requirements when they arrange transmission to support their
         wholesale sales and purchases as are required for third parties.
         Further, we expect that each public utility (or a control area
         operator acting as its agent) that provides transmission service
         must, at a minimum, give its customers electronic access in real
         time to information on transmission capacity availability,
         ancillary services, scheduling of power transfers, economic
         dispatch, current operating and economic conditions, system
         reliability, and responses to system conditions.
              This means that public utilities or their agents must give
         competitors and other users of the transmission system access to
         the same information available to the public utility personnel
         who trade (sell or purchase) power in the wholesale market, and
         at the same time.  Moreover, this information cannot be declared
         Docket No. RM95-9-000            - 4 -
         privileged (and kept from competitors) if it is available to the
         company's own employees who trade wholesale power.  Thus, if a
         utility wishes to keep this information confidential, it must
         assign control over this information to employees whose duties do
         not involve trading in wholesale power, and it must implement
         procedures to ensure that the traders do not get access to the
         information unless and until that information becomes public.
         The Commission invites parties to comment on the best way to
         implement these requirements in their comments and in their
         presentations at the Technical Conference and informal
         conferences.
              RINs should operate under industry-wide standards;
         otherwise, each RIN could contain different information, have
         different file formats, or use different means to transfer
         information between utilities and customers.  We are concerned
         that some customers (those who need transmission service across
         utility boundaries) might be forced to obtain information in
         different and perhaps incompatible environments.  Efficient
         wholesale power markets require that information formats not
         impede the ability of parties to make trades in a timely manner
         within and across utility boundaries.  Such impediments should be
         eliminated, or at a minimum, reduced to the maximum extent
         possible.
              In addition, we request comments on the following questions:
                   Information availability:  What information
                   should be available on a RIN?  Possibilities
                   include transmission availability data,
                   scheduling information, information on
         Docket No. RM95-9-000            - 5 -
                   economic dispatch, system reliability
                   conditions, service interruptions, and other
                   information that parties might suggest.
                   Would a RIN be appropriate, not only to
                   report transactions, but to conduct the
                   transactions themselves?  If so, for what
                   kinds of transactions would this be
                   appropriate?
                   RINs standards:  What standard formats would
                   be appropriate for transferring files
                   containing specific information?  What are
                   appropriate communication protocols?  How can
                   a RIN be designed to accommodate not only
                   today's needs, but also those in the future,
                   such as an ability to trade power and have
                   real-time price signals?
              Attached to this notice is a Staff Discussion Paper that
         gives Staff's preliminary views on some of the issues that need
         to be addressed in this proceeding.  We have attached this
         document to help the parties focus on pertinent issues as early
         in the process as possible.
         B.   Timetable for Comments, Technical Conference, and Informal
              Conferences
              The Commission's experience with Order No. 636 2/ and
         electronic bulletin boards (EBBs) in the natural gas industry
         3/ has taught us that when industry standards are needed, they

         2/   Pipeline Service Obligations and Revisions Governing Self-
              Implementing Transportation; and Regulation of Natural Gas
              Pipelines After Partial Wellhead Decontrol, 57 Fed. Reg.
              13,267 (April 16, 1992), III FERC Stats. & Regs. Preambles ¶
              30,939 (April 8, 1992); order on reh'g, Order No. 636-A, 57
              Fed. Reg. 36,128 (August 12, 1992), III FERC Stats. & Regs.
              Preambles ¶ 30,950 (August 3, 1992).
         3/   See Standards For Electronic Bulletin Boards Required Under
              Part 284 of the Commission's Regulations, Order No. 563, 59
              FR 516 (Jan. 5, 1994); III FERC Stats. and Regs.,
              Regulations Preambles ¶ 30,988 (1993), order on reh'g, Order
                                                            (continued...)
         Docket No. RM95-9-000            - 6 -
         should be established as early as possible.  We wish to avoid
         systems being developed, and expenses being incurred, before
         consensus can be reached on the best way to proceed.
              These same considerations also persuade us that a case-by-
         case approach to setting standards for electronic information
         transfer is inappropriate.  Public utilities should not be
         required to invest extensive capital in a RIN or EBB that might
         be obsolete in the near future. 4/
              We intend, therefore, to have requirements in place no later
         than the date when we issue any final rules on open access
         transmission.  In this way, we hope to avoid unnecessary
         expenditures by public utilities.
              At the Technical Conference, the Commission will focus on
         determining exactly what information must be made available to
         transmission customers and what standards are needed as to the
         transfer of this information on a real-time basis from
         transmission operators to their customers, including the public
         utility itself for its wholesale transactions.

         3/(...continued)
              No. 563-A, 59 FR 23,624 (May 9, 1994); III FERC Stats. and
              Regs., Regulations Preambles ¶ 30,994, reh'g denied, Order
              No. 563-B, 68 FERC ¶ 61,002, Order No. 563-C, order
              accepting modifications, Order No. 563-C, 68 FERC ¶ 61,362
              (1994).
         4/   We note that there is an extensive network already in place
              to conduct intercompany transactions reliably.  To the
              maximum extent possible, we intend to build on the existing
              institutional arrangements and ongoing efforts to help
              better schedule, monitor, and model transactions involving
              multiple control areas.
         Docket No. RM95-9-000            - 7 -
              The Technical Conference will be open to all interested
         persons.  The exact date, time, and location of the Technical
         Conference will be announced in a subsequent notice.
              To better organize the Technical Conference, interested
         persons are invited to submit written comments.  Comments must be
         received on or before [insert a date 60 days following the
         Federal Register publication date].  The comments should be no
         more than 25 pages in length, double spaced on 8½" x 11" paper,
         with standard margins.  Parties must submit fourteen (14) written
         copies of their comments.  In addition, commenters are requested
         to submit a copy of their comments on a 3½ inch diskette,
         formatted for MS-DOS based computers.  In light of our ability to
         translate MS-DOS based materials, the text need only be submitted
         in the format and version in which it was generated (i.e., MS
         Word, Wordperfect, ASCII, etc.).  It is not necessary to reformat
         word processor generated text to ASCII.  For Macintosh users, it
         would be helpful to save the documents in Macintosh word
         processor format and then write them to files on a diskette
         formatted for MS-DOS machines.  The comments must be submitted to
         the Office of the Secretary, Federal Energy Regulatory
         Commission, 825 North Capitol Street, N.E., Washington, D.C.
         20426, and their caption should refer to Docket No. RM95-9-000.
              All written comments will be placed in the Commission's
         public files and will be available for inspection or copying in
         the Commission's Public Reference Room (Room 3104, 941 North
         Capitol Street, N.E., Washington, D.C. 20426), during normal
         Docket No. RM95-9-000            - 8 -
         business hours.  The Commission also will make all comments
         publicly available on its EBB.
              Following the Technical Conference, the Commission's Staff
         will promptly schedule a series of informal conferences using, as
         appropriate, working groups enlisting the participants at the
         Technical Conference. 5/  The informal conferences are intended
         to narrow or resolve issues and to help the Commission determine
         what information must be made available, and what standards are
         needed, for the delivery of pertinent information on a real-time
         basis from transmission operators to their customers, including
         the public utility itself.
              Staff will designate what working groups are to be formed,
         when they will meet, and what topics they will consider.  Staff
         will work with these working groups as needed. 6/  The working
         groups will be invited to reach consensus on the issues and
         report that consensus to the Commission.  The working group

         5/   The Commission made use of working groups in drafting the
              Commission's standards for EBBs.  See, e.g., Standards For
              Electronic Bulletin Boards Required Under Part 284 of the
              Commission's Regulations, Final Rule, Order No. 563-A, 59 FR
              23624 (May 9, 1994); III FERC Stats. & Regs., Regulations
              Preambles ¶ 30,994 (1994).
         6/   To promote candor and productivity, Staff will set up and
              sponsor these meetings, but, where appropriate, will not
              attend the meetings while the parties discuss the issues.
              The parties are instructed, however, to brief Staff fully on
              their progress at any such meetings.
         Docket No. RM95-9-000            - 9 -
         reports should identify issues where no consensus is possible so
         that the Commission may take appropriate action to resolve all
         remaining technical issues.
         By direction of the Commission.
         ( S E A L )
                                            Lois D. Cashell,
                                               Secretary.
                                Staff Discussion Paper
                    Electronic Bulletin Boards and Real-Time Information Networks
                                            Introduction
             The Commission  has issued  a Notice of  Proposed Rulemaking,
         proposing non-discriminatory open  access transmission  services.
         The  NOPR proposes  that public  utilities provide  all potential
         wholesale  transmission  users,  including  the  wholesale  power
         marketing  department  of  the  transmission  owner, simultaneous
         access  to   transmission  and  ancillary  services.    Potential
         customers' access  to  information on  transmission capacity  and
         other matters  pertaining to  transmission services must  be made
         comparable  to  the information  access  available  to the  power
         marketing   department  of   the  transmission   owner  and   its
         affiliates.    Staff believes  that  electronic communication  is
         critical to achieving comparable  access to information, which in
         turn  is  a  cornerstone  of comparable  access  to  transmission
         service.   Comparable access  by customers  to information  as it
         becomes  available  is the  key to  both a  successful comparable
         access  program and  competitive  power markets  for electricity.
         Rapid transfer  of information  between a  transmitting utility's
         computers  and those  of its  potential wholesale  competitors is
         necessary to achieve these goals.  
             The  technical conference begins  the process  of determining
         what  information  and procedures  will  be  required to  achieve
         comparable  access  to  information.    We  request  comments  or
         concrete proposals  that address the issues  and questions raised
         in this paper.  Areas that need to be addressed include:
             ·   Information  Needs.    What  specific  information  is
                 required   to  ensure   that   all  eligible   parties
                 (including  the  transmission  owner) have  comparable
                 access to  information  needed  to  conduct  wholesale
                 power transactions over the transmission system?
             ·   Type   of   Information  System.      What  types   of
                 information  systems  are  available  to   communicate
                 transmission information, and which of these are  most
                 appropriate   to   achieve   comparable   access    to
                 information?
             ·   Standards and  Systems  Development.    What  standard
                 record  formats   should  be  developed  to   exchange
                 information?   What  protocols  are  needed?    Should
                 regional systems, or a national system, be developed?
             This   paper   provides   short   discussions    of   Staff's
         understanding of  the major  issues and  options in these  areas.
         Each  discussion is followed by  a list of  questions intended to
         guide comments.
         Docket No. RM95-9-000            - 2 -
           Docket No. RM95-9-000            - 3 -
                                Information Needed for Comparability
             Comparability requires that  wholesale transmission customers
         be provided with the same information that the transmission owner
         or   controller  has   about  the   availability  and   price  of
         transmission services,  and that  the information be  provided at
         the same time and cost.   A customer, when making wholesale power
         transactions using  transmission services,  should have  the same
         information  the  transmission   owner  has  available   to  make
         wholesale  power  transactions.     This  includes,  but  is  not
         necessarily limited to, the following types of information:
             ·   Availability   of   firm  and   non-firm  transmission
                 services  (including  ancillary  services), rates  for
                 these  services  and  the  amount  and  terms  of  any
                 available  rate   discounts.     Information  on   the
                 opportunity  costs  on  constrained   paths  and   the
                 incremental cost of expansion, if known.
             ·   Hourly  transfer  capacities  with  other  interfacing
                 control areas on a time interval  corresponding to the
                 interval that a transmission owner  uses in committing
                 its own  units.    For example,  if  the  interval  is
                 weekly, hourly transfer capacities  should be provided
                 each week  as the transmission  owner commits its  own
                 units.
             ·   Hourly amounts of  firm and  non-firm power  scheduled
                 over  each  of  the  owner's   interfaces  with  other
                 control  areas.     These  quantities  should  be  the
                 amounts  scheduled  over  the following  hour.    They
                 should be provided  at some short interval  before the
                 start of each hour (e.g., 15 minutes).
             ·   Transmission  outages,  or  planned  and  forced  unit
                 outages  that  may affect  trans-mission availability,
                 as  they become  known,  as  well as  anticipated  and
                 actual interruptions of services.
             ·   Load flow  data that would allow customers to do their
                 own   preliminary   review  of   incremental  transfer
                 capability   to   accommodate   long-term   transfers.
                 Updates  to  load  flow  information  should  be  made
                 available  to  customers  whenever  the   transmission
                 owner updates its load flow information.
             ·   Transaction specific information on  all requests  for
                 transmission   service  (including   requests  by  the
                 transmission   owner's   wholesale   power   marketing
                 personnel).  This information should  be sufficient to
                 permit  customers to  evaluate  the  current state  of
                 transmission  requests  on the  system and  to monitor
         Docket No. RM95-9-000            - 4 -
                 potential discrimination.  This information should  be
                 provided when requests  are received and  updated when
                 the status of a request changes.
             ·   Transmission   capacity   available   for  resale   by
                 customers   seeking   to  resell   their   rights   to
                 transmission    service,    and    announcements    by
                 prospective buyers  who are seeking to  acquire rights
                 to transmission  service.   These  requests should  be
                 made available when received.
             Staff believes  that transmission-owning  utilities have such
         information  available in  the  normal course  of business  under
         today's  current  industry  practices.    We  also  believe  this
         information  is  important  for any  parties  using  transmission
         services to perform  wholesale power transactions.   Accordingly,
         comparability requires that such information be made available to
         prospective customers and to  the transmission owner's  wholesale
         power  marketing department on the same basis.  However, the list
         is  provided only as an  example of our  current understanding of
         the  information.   We invite  comment on  additional information
         that  is  needed,  but  not included  in  the  list,  as well  as
         information in the list that is not needed.
             Current industry practice should not be the sole standard for
         judging what information to consider for inclusion in information
         networks.    Consideration  should  be  given  to  likely  future
         industry  developments, and  how  these might  affect information
         needs.   In particular, the role of electronic information in the
         dispatch function  may  change  significantly  as  power  markets
         change.  Future networks  may need to provide for  the electronic
         trading  of power.  The  design of current  systems should retain
         sufficient  flexibility  to  accommodate  these  types of  future
         developments.    We invite  comment  on  what developments  might
         affect  the  design of  a  current information  network,  and how
         consideration  of such  developments might  be considered  in the
         design of today's systems.
         Questions Regarding Information Needed for Comparability
           1.  What information  about capacity availability is  needed?  Is
             this information needed with respect to interfaces with other
             control areas and within a single control area?  
         2.  How often does  information on available capacity need  to be
             updated?  What other  information is necessary?  In designing
             RINs requirements,  what consideration should the  Commission
         Docket No. RM95-9-000            - 5 -
             give to  NERC's interest  in improving and  communicating the
             calculation of transfer capability in real-time. 7/
         3.  What  information about  transmission constraints  should  be
             included?    Is it  possible  to   develop  information about
             anticipated  constraints  and  their  associated  opportunity
             cost?  Could information on interruptions be conveyed after a
             constraint has occurred?
         4.  Should the  information  include  requests  for  transmission
             capacity, offers of  transmission capacity (from utility  and
             third  party  entitlement holders),  rates  and  an index  of
             entitlement holders?   How often does information  need to be
             updated?   What other information is  necessary to facilitate
             the  development  of  a  secondary  market  for  transmission
             capacity?
         5.  Can   requests   for   transmission   service  be   submitted
             electronically,  through an  EBB or  an information  network,
             rather than by  telephone or FAX?   What specific information
             is needed for electronic submission of transmission requests?
                     Systems for Communicating Transmission Information
                Many kinds  of information  systems could  support electronic exchange  of
           transmission information between a  transmission-owning public utility and its
           customers,  potential  customers,  and   the  transmission  owner's  wholesale
           marketing department.   But there is a  tradeoff between the cost  of a system
           and the capabilities  it offers.   We would like  comment on the  capabilities
           needed in a  system to communicate transmission  information and what type  of
           system will best meet those  needs.  In order to provide  technical background
           for this discussion, we offer the following three categories as general system
           types, from the simple to the more complex:
                ·   
                    Electronic Bulletin Board (EBB).  One simple method of elec-
                    tronically communicating information is to use EBB displays.
                    A user of  this type of  EBB simply connects to  (logs onto)
                    the EBB and sees the information displayed.  We believe this
                    simple  type  of  EBB should  also  permit  a  user to  post
                    information, such as a transmission request, to the EBB.    
                    This type  of information system  may be adequate  for small
                    customers who are not very active in the transmission market
                    and  who have only an  occasional need for  small amounts of
                    timely information.  However, as information needs increase,
                    the method of EBB  displays may become inadequate.   A major
                    disadvantage  is  that   displayed  information  cannot   be

         7/  See Report on Electric Utilities' Response to the Cold Wave
             of January 1994, Report by NERC Blue Ribbon Task Force at 10
             (Apr. 11, 1994).
           Docket No. RM95-9-000            - 6 -
                    processed directly  by the  receiving party's  own computer.
                    Thus, if the receiving  party wants to use  this information
                    in its own computer displays  or as part of an analysis,  it
                    must enter it again.  Reentering information is slow, error-
                    prone  and costly,  particularly  for users  who need  large
                    amounts  of information  from several  different EBBs.   For
                    this  reason, even the simplest form of EBB should provide a
                    capability  that permits  users to  capture the  information
                    presented in the display on their computer systems.
                ·   
                    EBBs with Standardized  File Transfer.   A second method  of
                    communicating information  is  to allow  users  to  transfer
                    files  between  the  EBB  and the  user's  computer  system.
                    Downloading  (transferring  the file  from  the  EBB to  the
                    user's  computer  system)  eliminates the  need  to  reenter
                    information into a user's computer system when it is already
                    present on the EBB.  Uploading (transferring a file from the
                    user's  system  to  the  EBB)  permits  information  already
                    present in a file on a user's
                    computer to be sent  to the EBB without  manual reentry.   Therefore,
                    the capability of transferring files  containing relevant information
                    between  the EBB and  its users solves  the data  reentry problem for
                    large and more sophisticated users.    
                    File  transfer  capability  also  makes  possible  efficient
                    processing  of  information  from  several  different  EBBs.
                    Computer  software  can  be  programmed  to  dial  each  EBB
                    automatically and to  transfer files from (or to)  each EBB.
                    The  user can then choose how to display the information, or
                    process it  directly in a  computer program.   Third parties
                    can aggregate transmission information from multiple EBBs to
                    provide an  information service for customers  who prefer to
                    use a single EBB.   Standard file formats and  protocols for
                    the transfer of information  are essential for the efficient
                    transfer of this information.   Without standard formats and
                    transfer protocols, a user must develop separate methods and
                    programs for transferring files to and from each EBB.
                ·   
                    Real-time Information  Network (RIN) Connection.   This type
                    of  network  permits  a  continuous  information  connection
                    between  the transmission-owning public utility and users of
                    the  transmission  network.    In   contrast,  displays  and
                    downloads are means of distributing information to users who
                    connect intermittently  to  an EBB  specifically to  request
                    information.   Continuous connection permits a user  to have
                    all new information as soon as it becomes available, without
                    needing  to make  specific requests.   A  user  can directly
                    monitor all  new information, or  use a computer  program to
                    monitor new information selectively as it becomes available.
           Docket No. RM95-9-000            - 7 -
                    The  computer  program  can   then  identify  time  critical
                    information as soon as it is available and alert key company
                    staff of the need to take action.
                    To  a  customer,  a  RIN  means  the  immediate  receipt  of
                    information when it becomes  available.  Only some customers
                    may need  information immediately, and  even these customers
                    will  not need  all  information immediately.   We  believe,
                    however,  that  some  customers   will  need  this  type  of
                    information  connection,  and  that  the   number  of  these
                    customers  will increase  over time  as markets  develop and
                    expand.  
                    RINs  would need  standardized  formats for  information and
                    protocols  for   its  transfer.    Such   standards  may  be
                    different,   and  more  complex,  than  standards  for  file
                    downloads and uploads.   However, the  development of a  RIN
                    could eliminate  the need to develop  separate file transfer
                    capabilities  through  EBB  uploads  and  downloads.    Such
                    networks  could  be  designed  to  support  both  continuous
                    connection and  intermittent access using  the same  formats
                    and transfer protocols.
           Docket No. RM95-9-000            - 8 -
           Questions Regarding the Means of Communicating Information
           6.   What  information is  sufficiently  time sensitive  to  require  real-time
                transmission and  receipt?   What information  is sufficiently  unchanging
                and time insensitive to permit efficient  transmission by request?  Should
                the amount and timing of real-time information provided be a user option?
           7.   Is an  EBB  requirement necessary  at  all  if transmission-owning  public
                utilities are required to provide information to, and receive  information
                and requests  from,  an information  network?    Would EBBs  be  developed
                voluntarily, either by utilities or third  parties, if data were available
                through an information network?
           8.   What is the minimum  acceptable transfer time for the network?  Should  it
                be  measured in milli-seconds,  seconds or  minutes?   Should the transfer
                time be a function of the information transferred?
           9.   Should EBBs  and/or RINs  be developed  in several  phases?   If so,  what
                phases and timing are appropriate?
           10.  How  can the  development of  EBBs and  RINs  be  made flexible  enough to
                accommodate future information needs?
           11.  Should the network be developed using lines leased  or can it use existing
                Value Added Networks (VANs)?
                                  Standards and System Development
                Standardization  of information,  record formats,  and protocols  for  the
           exchange  of  information  are  crucial to  computer-to-computer  transfer  of
           information.    Without standards,  each utility  could  develop its  own file
           formats and protocols to  govern the transfer of  information.  As  experience
           with the development of EBBs in the gas industry has  shown, different formats
           and communication  methods impose significant  costs on using  information and
           provide barriers to trade across multiple companies.  Moreover, once companies
           design their own information  systems, they understandably tend to  resist the
           imposition  of generic  standards.   It is  therefore especially  important to
           reach  consensus on what standards  should govern the  operation of electronic
           information  systems  and how  information  systems  should  be  developed  in
           accordance  with those standards.  We would also  like comment on how the cost
           of system development and use should be recovered.
           Questions Regarding Standards and System Development
           12.  What  standard  information should  be  included  in  the  datasets to  be
                exchanged electronically?   What standard definitions and units should  be
                used for this information?
           Docket No. RM95-9-000            - 9 -
           13.  What  standard record  formats  and  identification codes  are  needed  to
                exchange the information associated with comparable access?
           14.  What   standard   codes   should   be   used   to   identify   facilities,
                interconnection points, and other locations?
           15.  What  standard  protocol(s)  should be  developed to  download  and upload
                files, or to exchange information across the information network?
           16.  Should a regional or national information system be developed?
           17.  If  some regional  development of  information systems  is desirable, what
                regional entities  should  develop and  maintain  the  system?   Do  these
                entities  currently exist?    If  they do  not exist,  how should  they be
                developed?
           18.  What  system  development  and  usage  costs   should  be  borne  by   all
                transmission users,  and what costs should  be paid for  only by users  of
                the information system?