DR 98-012
                      Granite State Electric Company
                   Offer of Settlement for Retail Choice
                Order Approving Amended Offer of Settlement
                         O R D E R   N O.  23,041
                              October 7, 1998
         APPEARANCES: Thomas Robinson, Esq. for New England
     Power Company; Carlos A. Gavilondo, Esq. for Granite State
     Electric Company; LeBeouf, Lamb, Green & MacRae by Susan Geiser
     and Lisa Terrizzi, Esquires on behalf of the Unitil Companies;
     Gerald M. Eaton, Esq. for Public Service Company of New
     Hampshire; McLane, Graf, Raulerson & Middleton by Steve Camerino
     on behalf of Great Bay Power; Sylvester Swierzy on behalf of
     EnerDev and Granite State Taxpayers Association; Julie Hashem for
     MainePower; Robert Rossignol for Alternate Power Source; David
     Parsons for Wheeled Electric Power; James Rodier, Esq. pro se;
     Pentti Aalto for PJA Energy Systems; Anne Ross, Esq. on behalf of
     Retail Merchants Association; Rubin and Rudman by John Detore and
     Donna Sharkey, Esquires on behalf of Enron Capital & Trade
     Resources; James Monahan  for Cabletron Systems; Foley, Hoag &
     Elliot by James Brown, Esq. and Stephen J. Judge and Wynn E.
     Arnold, Esquires, for the Governor's Office of Energy and
     Community Services; Robert Backus, Esq. on behalf of the Campaign
     for Residential Ratepayers; David W. Marshall, Esq. for the
     Conservation Law Foundation; the Office of Consumer Advocate by
     Michael W. Holmes, Esq. on behalf of Residential Ratepayers;
     Eugene Sullivan, III and Robert J. Frank, Esquires, for the Staff
     of the New Hampshire Public Utilities Commission.
               In accordance with the public good standard of RSA
     374:30 and consistent with the restructuring principles set forth
     in RSA 374-F and the recently enacted law, SB 341, as described
     below, this order approves the Amended Offer of Settlement
     (Amended Settlement) filed by Granite State Electric Company
     (GSEC or Company) on July 13, 1998.  On February 3, 1998, GSEC
     filed a Restructuring Settlement Agreement (Settlement) which was
     intended to represent a final and comprehensive resolution of
     issues associated with the advent of retail electric competition
     in New Hampshire as they pertain to GSEC and its customers.  The
     Offer of Settlement was supported by a number of parties,
     including the Governor, Representatives Bradley and Below,
     Senators King and Fraser, and a number of groups and
     organizations representing various customer and environmental
     interests.  A number of parties, including Cabletron, Retail
     Merchants Association, James Rodier, the City of Manchester, the
     Office of Consumer Advocate, and Staff opposed some parts of the
     Settlement, though they indicated they would support the
     Settlement with certain modifications. 
               After extensive testimony, six days of hearings, almost
     60 exhibits, and nine briefs, the Commission indicated at a
     public meeting on June 26, 1998, that it would approve the
     Settlement with some modifications.  Those modifications included
     changes to transition service, the elimination of the mitigation
     incentive payment, a reduction in the post-divestiture cost of
     equity for calculation of the contract termination charges,
     elimination of that portion of the systems benefits charge
     related to a renewable energy commercialization fund and changes
     to the Settlement's proposal on energy efficiency to conform with
     Order No. 22,875 (March 20, 1998), the Commission's Order on
     Rehearing in Docket No. DR 96-150, the generic docket on
     Restructuring New Hampshire's Electric Utility Industry. 
               In its cover letter to the July 10, 1998 Amended
     Settlement, GSEC indicated that all signatories to the Settlement
     except Conservation Law Foundation and the Northeast Energy
     Efficiency Council agreed to accept the modifications as
     presented by the Commission in its oral statement of June 26,
     1998.  The Amended Settlement represents significant benefits for
     GSEC's customers.  The Amended Settlement will bring near-term
     rate relief for GSEC's customers, open GSEC's service territory
     to retail choice sooner than litigation would allow, establish
     transition service rates which should incent greater competition
     than has materialized in either Rhode Island or Massachusetts,
     establish reasonably low stranded cost charges while resolving
     the stranded cost issue for GSEC, provide for low income support
     consistent with our previous orders, and remove GSEC from
     participation in the federal lawsuit against the Commission.  
               The Commission, however, notes herein that, consistent
     with passage of SB 341, An Act relative to the implementation of
     electric utility restructuring, which became effective July 17,
     1998, approval of this Amended Settlement should not be
     considered a precedent for other settlements that are presently
     before us or may be forthcoming.  Our approval of the Amended
     Settlement is "appropriate to the particular circumstances" of
     GSEC only.  See RSA 374-F:3,V(d)
               On February 3, 1998, Granite State Electric Company
     filed with the Commission a Restructuring Settlement Agreement
     relative to restructuring the electric utility industry as it
     affects GSEC and its customers, that was jointly sponsored by the
     Governor of the State of New Hampshire, the Campaign for
     Ratepayers' Rights (CRR), Granite State Taxpayers, Inc. (GSTI),
     EnerDev, Inc. (EnerDev), the Electric Utility Restructuring
     Collaborative (Collaborative) with the exception of the City of
     Manchester which takes no position on the Settlement, 
     Conservation Law Foundation (CLF), the New Hampshire Business and
     Industry Association (BIA), Northeast Energy Efficiency Council,
     Inc. (NEEC), Senators Frederick W. King and Leo W. Fraser, Jr.,
     Representatives Clifton C. Below and Jeb E. Bradley, New England
     Power Company (NEP) and Granite State Electric Company
     (collectively, the Sponsors).  
               On February 11, 1998, the Commission issued an Order of
     Notice requiring a Pre-hearing Conference to consider the issues
     be held February 27, 1998; that parties wishing to intervene do
     so by February 24, 1998; and that parties wishing to object to
     petitions to intervene file objections by February 26, 1998. 
     Notice of the filing was published in the Valley News on February
     12, 1998 and in the Union Leader on February 14, 1998.  The
     Commission received 10 timely motions for intervention and 5 late
     filed motions.  At the February 27, 1998 hearing, Messrs. Jim
     Rodier, Esq., Sylvester Swierzy, and Pentti Aalto made oral
     motions to intervene, after which the Commission granted all
     petitions for intervention.  (Tr. February 27, 1998, p.12)  Also
     at the February 27, 1998 hearing, Commission Staff, the OCA,
     Cabletron Systems, Inc., Enron and RMA argued that the petitions
     and the issues to be addressed in this docket and the then
     pending docket, DE 97-251, regarding the transfer of New England
     Power Company's generation assets to USGen New England, Inc.
     (USGenNE) were so fundamentally intertwined that they could not
     be addressed separately.   
                    RMA moved orally to consolidate this docket with the
     transfer docket.  On March 2, 1998, the Company submitted a
     Transition Service compliance filing.  On March 9, 1998, GSEC
     filed a draft proposed scoping stipulation that was supported by
     GSTI, EnerDev, the Collaborative (excluding Manchester), BIA, and
     Reps. Below and Bradley for dockets DE 97-251, the transfer
     docket, and DR 98-012, the Offer of Settlement docket. 
               On March 10, 1998, RMA filed a written motion in
     support of its February 27, 1998 oral motion, with which OCA and
     Manchester concurred.  On March 10, 1998, Staff filed a
     memorandum in support of RMA's motion.  
               GSEC submitted a response on March 11, 1998, which it
     characterized as a clarification of the record, reiterating its
     position that consolidation was unnecessary and would not promote
     the orderly and efficient conduct of either proceeding.  On
     March 30, 1998, the Commission issued Order No. 22,886 granting
     the various motions to intervene, denying RMA's motion to
     consolidate dockets DE 97-251 and DR 98-012, and accepting the
     scoping stipulation filed by GSEC on March 10, 1998.  In
     addition, in its Order No. 22,886, the Commission approved a
     procedural schedule for docket DR 98-012 and ratified the
     procedural schedule for docket DE 97-251.  
               On May 1, 1998, the Commission, by executive letter,
     directed the parties to address in legal memoranda, by May 13,
     1998, the issues arising from the Companies' filing with the
     Federal Energy Regulatory Commission (FERC) in which the
     Companies sought and on April 28, 1998 FERC granted (New England
     Power Company, Inc., 83 F.E.R.C. 61,085 (1998)) approval of an
     amendment to the Companies' wholesale requirements agreement
     (Granite State Amendment) to accommodate retail electric
     competition.  Because the Granite State Amendment includes, inter
     alia, the same contract termination charges (CTC) that the
     Companies requested this Commission to "review and approve," the
     Commission directed the parties to set forth, in legal memoranda,
     their positions regarding the Commission's jurisdiction and legal
     authority to set retail stranded cost charges, to be collected by
     GSEC from its retail customers, that differ from the rates, terms
     and conditions of the contract termination charges approved by
     the FERC. 
          The Commission further directed the Parties to include in
     their responses a discussion of the effect on the issues raised
     by the Commission's questions of the "filed rate doctrine" as
     established and defined by the United States Supreme Court in,
     inter alia, Nantahala Power and Light v. Thornburg, 476 U.S. 953 
     (1986); and Mississippi Power and Light Company v. Moore, 487
     U.S. 354 (1988), and the New Hampshire Supreme Court in Appeal of
     Northern Utilities, 136 N.H. 449 (1992).
               Hearings were held May 26, 27, 28 and 29, 1998 and on
     June 2 and 3, 1998.  Post-hearing briefs were filed by the
     Governor's Office of Energy and Community Services (ECS), GSEC
     and NEP, CLF, Unitil, OCA, and Enron.  RMA, Cabletron, James
     Rodier and the Commission Staff submitted a joint brief.  In
     addition, post-hearing comments were submitted by Representatives
     Below and Bradley and Mr. Pentti J. Aalto.  In addition to the
     post-hearing briefs, the extensive record includes the testimony
     of the Companies' and other Sponsors' witnesses and the testimony
     of the other Parties and Staff.  
               In a public meeting held June 26, 1998, the Commission
     deliberated the Offer of Settlement and imposed certain
     modifications consistent with its authority under
     RSA 374-F:4,III.  On June 29, 1998, the Settling Parties
     submitted a response to the Commission's deliberations.  Letters
     were received from OCA and Cabletron, dated June 30, 1998,
     opposing the response of the Settling Parties and raising
     procedural questions.  On July 1, 1998, the Commission issued an
     executive letter stating that, after reviewing the June 29, 1998
     letter and materials supplied by GSEC, the Commission determined
     that the Settling Parties did not accept all of the conditions as
     they were deliberated on June 26, 1998.  The Commission scheduled
     a hearing for July 7, 1998 to provide the Settling Parties an
     opportunity to explain their filing, to answer any questions from
     the Commission or any Parties about their filing, and to provide
     any party with an opportunity to comment on the June 29, 1998
               On July 6, 1998, Enron submitted comments and requested
     that its comments be included in the record in DR 98-012.  On
     July 7, 1998, the Commission received a letter from GSEC
     requesting a delay in the hearing scheduled for 9 a.m. that day
     and withdrawing its June 29, 1998 filing.  Due to the lateness of
     GSEC's request, the Commission was unable to reschedule the
     hearing.  At the July 7, 1998 hearing, various parties indicated
     that the original parties to the Settlement were still discussing
     their respective positions on the Commission's Oral
     Deliberations.  The Commission then granted GSEC until the close
     of business on July 10, 1998 to report the status of negotiations
     among the settling parties. 
               On July 13, 1998, GSEC filed a response to the
     Commission's Oral Deliberations of June 26, 1998 and letter of
     July 1, 1998 stating that the Company accepted the Commission's
     modifications to the Settlement.  Reflecting its acceptance of
     the Commission's modifications, the Company submitted a
     Restructuring Settlement Agreement marked-to-show changes from
     the initial Settlement Offer along with revised post-divestiture 
     contract termination schedules. 
               On July 15, 1998, the Commission issued Order No.
     22,981 authorizing GSEC to reduce rates retroactive to July 1,
     1998 and to proceed to implement retail choice in its service
     territory based upon the modifications contained in the Amended
     Settlement filed on July 13, 1998.  In addition, the Commission
     directed the Company to file compliance tariff pages in
     conformance with Order No. 22,981.  GSEC submitted its compliance
     filing on July 16, 1998.  
               On July 22, 1998, the OCA submitted a letter
     identifying certain stranded cost issues contained in the Amended
     Offer of Settlement. 
               On August 17, 1998, the Company submitted post-divestiture revised tariff pages and requested that the
     Commission issue an order authorizing GSEC to reduce its rates to
     reflect the pending closing of the transfer of NEP's non-nuclear
     generating assets to USGenNE which it estimated would occur on or
     about September 1, 1998.  On August 31, 1998, the Commission
     issued Order No. 23,005 authorizing GSEC to reduce rates by an
     additional 7 percent effective upon the closing of the
     NEP/USGenNE asset transfer.  
               On October 1, 1998, the Company filed with the
     Commission a copy of a Request for Qualifications to Provide
     Transition Service Electricity Supply to Granite State Electric
     Company (RFQ).  The RFQ, which was based on the March 2, 1998
     Transition Service compliance filing, modified to reflect the
     timing of the auction and the term for Transition Service, was
     issued by the Company to over seventy potential power suppliers. 
     In its transmittal letter, GSEC states that responses to the RFQ
     are due November 2, 1998 and that the Company intends to conduct
     the auction on December 1, 1998 for service to commence
     January 1, 1999.  
               The Commission initiated Docket No. DR 96-150 to
     address the requirements set forth in RSA 374-F, the State's
     electric restructuring law.  Following its generic investigation,
     on February 28, 1997, the Commission issued Restructuring New
     Hampshire's Electric Utility Industry: Final Plan (the Plan). See
     Order No. 22,514.  Concurrently and in accordance with RSA 374-F,
     the Commission issued Order No. 22,511 specific to GSEC which,
     among other things, established stranded cost charges on an
     interim basis pending a final determination of GSEC's stranded
     costs.  See Order No. 22,511 at 15.   
               On March 20, 1998, the Commission issued Order No.
     22,875, its Order on Requests for Rehearing, Reconsideration, and
     Clarification (Order on Rehearing) in DR 96-150. The Order on
     Rehearing addressed various motions for reconsideration
     concerning, among other things, transition service, stranded cost
     recovery, affiliate transactions and certain public policy
     findings related to renewable energy and energy efficiency. 
     Implementation of restructuring pursuant to the Commission's
     directives in Order No. 22,875 has been suspended pending ongoing
     federal court action.  The Settlement is intended to resolve
     comprehensively and finally the electric restructuring issues for
     GSEC.  It also is intended to end GSEC's involvement in the
     litigation in federal district court.  Due to the federal
     district court action and absent the voluntary Offer of
     Settlement, the Commission could not compel GSEC to comply with
     retail choice pursuant to the Plan or the Commission's Rehearing
     Overview of the Offer of Settlement
               The Offer of Settlement is comprised of the
     Restructuring Settlement Agreement and seven attachments.  The
     complete Offer of Settlement is contained in two books.  Book 1
     includes the retail-related aspects of the Settlement and
     includes the Restructuring Settlement Agreement and Attachment 1:
     Rate Design; Attachment 3: Proposal for Environmental Component;
     Attachment 4: Description of Hydro Facilities; Attachment 5:
     Summary of Contracts; Attachment 6: Evaluation of FERC's Seven
     Factor Test; and Attachment 7: Transition Service Framework. 
     Attachment 2 is contained in Book 2 and includes the Wholesale
     Settlement between GSEC and NEP.  Book 2 was filed at the Federal
     Energy Regulatory Commission (FERC) on February 27, 1998.
                    GSEC states that the Offer of Settlement is consistent
     with the requirements of RSA 374-F and SB 341, is substantially
     consistent with the Commission's restructuring orders in Docket
     No. DR 96-150 and should be approved.  Brief at 2.  GSEC avers
     that the Settlement provides a final and comprehensive resolution
     of the issues raised by electric utility restructuring in
     DR 96-150.  GSEC contends that, absent the Settlement, most of
     the issues would remain unresolved pending the outcome of the
     federal district court case in Rhode Island and subsequent
     Commission proceedings.  As described in the Offer of Settlement
     under Section XV. Additional Provisions, if the Offer of
     Settlement is not approved as filed, GSEC and the other sponsors
     have reserved the right to amend voluntarily the Offer of
     Settlement and refile the amended Settlement; however, GSEC
     states that the sponsors may terminate the Offer of Settlement if
     the Commission disapproves the Offer of Settlement in a manner
     that cannot be voluntarily and consensually amended.  Ex. 1 at
     35, Ex. 37, Arcate at 4.  If terminated, the Offer of Settlement
     would be considered withdrawn and could not be used or referred
     to in any other proceeding, including Docket No. DR 96-150;
     however, GSEC would proceed with its May 1, 1998 compliance
     filing based on the Commission's Order on Rehearing and introduce
     retail choice by July 1, 1998.  Ex. 37, Arcate, at 4.         
               The Settlement provides for customer choice to commence
     in GSEC's service territory upon the closing of the sale of NEP's
     non-nuclear generating assets to USGenNE or on July 1, 1998,
     whichever occurs first.  The Settlement also guarantees savings
     to customers, establishes a transition service option for all
     customers who do not choose to take electric service from a
     competitive provider, provides full stranded cost recovery for
     GSEC as a result of its early termination of its all-requirements
     wholesale contract with NEP, accelerates funding of GSEC's share
     of NEP's decommissioning costs of the Seabrook Nuclear power
     plant, requires specific environmental improvements associated
     with emissions from NEP's Salem Harbor and Brayton Point power
     plants, makes a commitment to continued conservation programs at
     current financial levels, provides support for clean, renewable
     energy projects, and establishes support for low income
     Description of the Offer of Settlement
           I.  Implementation of Retail Choice 
               The Settlement states that GSEC will unbundle retail
     delivery tariffs to allow customers to choose their generation
     supplier effective on the Retail Access Date, which is the
     earlier of July 1, 1998, or the Divestiture Date.  The
     Divestiture Date refers to the date that NEP closes the sale to
     USGenNE, or if that transaction fails, the date NEP closes the
     sale, spin-off or other disposition of its non-nuclear generating
     assets to a third party.
          II.  Stranded Cost Recovery
               The Settlement provides for the final resolution of
     GSEC's stranded costs due to New Hampshire electric
     restructuring.  On the Retail Access Date, NEP will no longer
     provide GSEC with full all-requirements service as provided for
     under its FERC wholesale tariff, FERC Electric Tariff, Original
     Volume No. 1 (Tariff No. 1).  In its place, GSEC and NEP have
     agreed to an amendment to Tariff No. 1 which grants GSEC early
     termination of its wholesale purchase obligations in return for a
     Contract Termination Charge (CTC) paid by GSEC to NEP to
     compensate NEP for the costs it incurred to serve GSEC under
     Tariff No. 1 (Tariff No. 1).  The Settlement provides that GSEC
     will be authorized to recover in retail rates, on a fully
     reconciling basis, the stranded costs as described in the CTC.   
               The stranded cost charges are fixed at 2.8 cents per
     kWh from the Retail Access Date through December 31, 1999.  The
     CTC declines, thereafter, subject to adjustments.  Those
     adjustments, detailed in Book 2 (Ex. 1A), include a reduction for
     the Residual Value Credit, and Interim Residual Value Credit, and
     a risk and reward sharing mechanism.  Book 2 includes post-divestiture schedules showing the effect of the closing of the
     NEP/USGenNE transaction.  
               The Sponsors state that the stranded costs established
     in the Settlement are equitable, balanced and appropriate when
     viewed in the context of the Settlement.  Furthermore, they aver
     that the stranded costs are substantially consistent with the
     policy principles for restructuring as set forth in RSA 374-F and
     request that the Commission make that finding.
          III. Guaranteed Savings to Customers
               Upon the Retail Access Date, GSEC will provide
     unbundled service which includes distribution rates as shown in
     Attachment 1 of the Settlement, including a distribution
     surcharge for recovery of various expenses and costs such as the
     Pilot Program and a December 1996 storm, recoverable over 2
     years, fully reconciling stranded cost charges, fully reconciling
     transmission charges billed to GSEC from NEP, charges for
     Transition Service and charges to fund energy efficiency,
     renewable energy and low income programs.  The Settlement
     provides customers with the opportunity to receive at least 10
     percent savings, on average, from their current bundled bill.
     After completion of the NEP/USGenNE sale, customers' total
     savings will be approximately 17 percent.  Greater savings are
     possible if customers procure service from competitive suppliers
     at prices below Transition Service prices.  
               Transition Service, available to GSEC's customers of
     record as of the Retail Access Date and to those new residential
     and small commercial customers who request service from GSEC
     within 120 days from the Retail Access Date, is intended to
     provide all customers with stable prices as the competitive
     electric market develops while maintaining the opportunity for
     savings.  Qualified suppliers for Transition Service will have
     the opportunity to supply Transition Service at prices which are
     at or below the Backstop prices contained in the NEP/USGenNE
     agreement.  Those prices are: 1998 - 3.2 cents per kWh; 1999 -
     3.5 cents per kWh; 2000 - 3.8 cents per kWh; 2001 - 3.8 cents per
     kWh; and 2002 (through June) - 4.2 cents per kWh.  All prices
     reflect flat rates for service delivered to the customer's meter
     and do not include the costs for distribution, transmission or
     other delivery related costs.  Ex. 1, Attachment 7.
               Transition Service includes a Fuel Price Index
     Adjustment in the event that substantial increases in No. 6
     residual fuel oil (1% S) and natural gas occur after January 1,
     2000.  If the Fuel Trigger Point is exceeded for any billing
     month during the effective period, GSEC will pay additional
     amounts to the suppliers in accordance with the formula set out
     in the Fuel Price Index Adjustment.  Ex. 1, Attachment 7.  
               From January 1, 1999, the rates for residential
     Domestic Rate D customers are subject to an inflation cap
     adjustment based on the Gross Domestic Product Implicit Price
     Deflator using January 1, 1998 as the starting point.  The
     inflation cap and rates are also subject to a fuel price index
     for Transition Service as set forth in Attachment 7.        
          IV.  Default Service
               Default service is available to customers who for a
     period of time have left their competitive supplier and have not
     begun receiving service from another or the same competitive
     supplier.  Default service will be provided in a manner
     consistent with Commission guidelines on default service.  GSEC
     will fully recover any costs associated with providing default
     service through a separate adjustment in rates.
           V.  Low Income Provisions 
               GSEC proposes to implement a low income program (the
     Affordability Program) designed to make electric service more
     affordable.  The Affordability Program, which would provide low
     income customers a discount off their bill, would be funded
     through a wires charge.  Absent adoption by the Commission of a
     percentage of low income program, GSEC would file a low income
     discount rate intended to provide low income customers with an
     equivalent level of rate relief. 
               On the Retail Access Date, GSEC will provide low income
     customers with a safety net service it describes as a type of
     Default Service for low income customers.  GSEC will
     competitively procure that service.  The cost of the low income
     discount and power supply costs associated with the program are
     recoverable through a separate adjustment in GSEC's distribution
     charges billed to all customers.  GSEC has also committed to the
     development of a plan to back the bad debt service of low income
     customers in order to reassure competitive suppliers and reduce
     the potential of "redlining".  The plan would be subject to
     Commission review and approval.
          VI.  Environmental Improvements, Conservation and Renewables          NEP or any successor commits to reduce air emissions of
     NOx and SO2 at plants located in Massachusetts.  Those plants
     include Salem Harbor Units 1,2,3, and 4 and Brayton Point Units
     1,2,3, and 4.
               The Settlement includes a non-discriminatory, non-bypassable wires charge of 3.5 mils per kWh on average over a 5-year period effective from the Retail Access Date for DSM and
     renewable energy commercialization programs.  GSEC will be
     allowed the opportunity to earn incentives on the DSM programs. 
               VII. Nuclear Decommissioning and Divestiture
               NEP, a minority owner in six nuclear power plants and a
     9.98 percent owner in the 1,150 MW Seabrook Nuclear power plant,
     will accelerate its funding for nuclear decommissioning costs at
     Seabrook Unit 1.  The agreed upon accelerated funding is intended
     to adequately provide a level of decommissioning funds should:
     (1) Seabrook Unit 1 be retired 25 years from the commencement of
     its nuclear operating license; (2) the methodology for
     calculating nuclear decommissioning costs changes to reflect
     nominal levelized payments; or (3) the estimated cost of
     decommissioning Seabrook Unit 1 increases by up to 20 percent. 
     GSEC's allocated portion of the nuclear decommissioning funding
     from NEP would be at least $100,000 per year.
               NEP also agrees to sell, assign, lease or dispose of
     its minority interest in its nuclear units and entitlements.  By
     July 1, 1999, NEP will file a plan with the Commission
     demonstrating its best efforts to accomplish divestiture of its
     nuclear entitlements.  Prior to divestiture of its nuclear
     assets, NEP shall implement a risk/reward sharing mechanism which
     allows operating profits or costs to be apportioned to NEP at 20
     percent and to GSEC's customers at 80 percent.       
          VIII. Divestiture of Generation Assets
               On August 5, 1997, NEP agreed to sell or otherwise
     transfer its ownership interest in substantially all of its non-nuclear generating assets to USGenNE.  As part of the wholesale
     rate settlement filed with FERC and contained in the Offer of
     Settlement as Attachment 2, GSEC will receive its pro rata share
     of the proceeds of the sale in the form of a Residual Value
     Credit to reduce stranded costs.  The Sponsors agree to support
     the application of the transfer between NEP and USGenNE at the
     FERC, filed on October 1, 1997, as well as NEP's filing with this
     Commission in DE 97-251, and to request that the New Hampshire
     Public Utilities Commission support NEP's request at the FERC and
     grant NEP's petition in DE 97-251. 
           IX. Approval of Transfer of Hydro Facilities
               Also included in DE 97-251 is NEP's petition pursuant
     to RSA 374:30 to transfer its hydroelectric facilities located in
     New Hampshire to USGenNE.  Attachment 4 to the Offer of
     Settlement describes NEP's hydroelectric facilities in New
                 X. Market Pricing and Exempt Wholesale Generation Status
               The Sponsors of this Settlement have filed with the
     Commission in DE 97-251 a request that the Commission find in the
     public interest that NEP or its successors or assigns, including
     USGenNE, be authorized to sell power in the wholesale market.  In
     that request, the Sponsors also asked the Commission to find that
     NEP or its successors or assigns be allowed exempt wholesale
     electricity generator status pursuant to Section 32 of the Public
     Utility Holding Company Act of 1935. 
           XI. Jurisdictional Separation Between Transmission and
               Attachment 6 of the Settlement provides an overview and
     evaluation of the structure of New England Electric System, Inc.
     (NEES) as it pertains to the FERC's definition of transmission
     and local distribution described by FERC in its seven factor test
     in Order No. 888.   
          XII. Marketing Affiliates
               The Sponsors state that affiliates of GSEC should be
     allowed to compete for the electricity, energy, and competitive
     services of customers throughout New Hampshire, including those
     customers in GSEC's service territory pursuant to standards of
     conduct approved by the Commission.  Affiliate sales will not
     take place in GSEC's service territory until Commission approved
     standards of conduct become effective.
          XIII. Waiver of Certain Contractual Obligations
               Effective on the Retail Access Date, GSEC agrees to
     waive certain contract and tariff provisions in order to allow
     customers with minimum notice provisions to participate in retail
     competition.  Those waivers pertain to customers served under
     Cooperative Interruptible Service (CIS) Agreements, Service
     Extension Discounts, and those nonresidential customers who have
     participated in GSEC's conservation and load management programs
     which require repayment of GSEC's incentives if the customer
     chooses an alternative electricity provider.  Additionally, the
     General Service (Rate G) tariff requires all customers to provide
     one year prior written notice before they may choose an
     alternative power provider or install additional on-site
     generation for their own use.  
               The Settlement does not require GSEC to waive the
     advance written notice requirement needed by customers before
     they may install on-site non-emergency generation for their use
     or to bypass the GSEC distribution system.  
               If the Service Extension Discount or CIS Provisions are
     not already closed, effective January 1, 1998, GSEC will close or
     cease to offer those rates and incentive clauses to new
          A.   Enron
               Enron's focus in this proceeding is Transition Service
     although it notes that the issues in this proceeding and in
     DE 97-251 are complex and interrelated.  Enron cites its
     testimony and arguments concerning NEP's divestiture proposal
     filed in DE 97-251 and the Commission's decision to incorporate
     the record in that proceeding into the record in this proceeding. 
     Enron supports the Commission's policy as stated in Order No.
     22,875 that a competitive bidding process should be used to
     select supply resources for Transition Service. 
               Enron contends that true competition cannot occur if
     transition service bids incorporate a price cap substantially
     below market price.  Brief at 2.  Enron points to the Standard
     Offer auctions held in Massachusetts by NEES and Commonwealth
     Electric Company/Cambridge Electric Light Company as examples of
     failed Standard Offer auctions.  Based on those examples and the
     record in this proceeding, Enron urges the Commission to reject
     the proposed Settlement, including Transition Service prices
     based on Exhibit 50, because it will delay true competition for
     several years and does not meet the principles of RSA 374-F:2,
                    With respect to the response of Cabletron, RMA, James
     Rodier and Staff to Exhibit 50, Enron supports much of the
     material contained in that filing; however, Enron urges the
     Commission to adopt the LaCapra market price projections (from
     DR 96-150) or, in the alternative, to adopt Mr. McCluskey's
     proposal to allow the market to determine the appropriate prices
     for retail customers served under transition service.   
          B.   OCA 
               The OCA urges the Commission to use Dr. Rosen's
     estimate of future wholesale prices developed for this
     proceeding.  Ex. 22.  In order to protect ratepayers from paying
     more than 100% of stranded costs, the OCA states that Dr. Rosen's
     bottoms-up estimate of future wholesale prices must be used
     consistently for the determination of Transition Service prices,
     the economics of divestiture and the calculation of stranded
     costs in order to protect ratepayers from paying more than 100%
     of stranded costs.  Brief at 1.  
     Transition Service 
               The OCA offers three reasons why competition won't
     occur by the end of the Transition Service period as proposed in
     the Settlement:  the stranded costs will be collected in rates,
     large customers may have special pricing arrangements, and
     residential customers will remain tied to a monopolistic system
     that differs little from what is in place today.  Brief at 2. 
     Dr. Rosen proposes starting with his wholesale price estimates
     and adjusting them to account for additional costs necessary to
     serve residential customers at retail.  Brief at 4. 
               Dr. Rosen proposes the following retail prices which he
     believes will clear the market for residential customers during
     the transition period:
                            Retail Adder
                                            Exhibit #55
     Dr. Rosen would reduce the retail adder by one-half for large
     customers.  The OCA points out that these prices are lower than
     those used by LaCapra and adopted by the Commission in DR 96-150
     when adjusted for retail.  
               To set the wholesale market price, Dr. Rosen proposes
     an auction of the backstop supply which incorporates simultaneous
     bids by up to three suppliers.  Due to the minimal additional
     costs incurred by these "bulk providers", the retail price would
     be only slightly higher: 2 mils per kWh for large customers and 4
     mils per kWh for small customers.  Additional adjustments would
     be needed due to the different load factors and losses of the
     Stranded Costs 
               The OCA points out that as market price increases,
     stranded cost decreases.  For GSEC, the rate of the 
     relationship between market price and stranded cost differs
     depending on whether the stranded costs are looked at in the pre-divestiture or post-divestiture case.  Dr. Rosen asserts that as
     the market price increases, stranded costs in the post-divestiture case increase relative to the pre-divestiture case
     and remain higher.  OCA contends that the market prices (both
     pre-and post-divestiture) used by GSEC are too low, overstating
     stranded costs by as much as $360 million post-divestiture or $11
     million for GSEC's customers.  Customers will have to pay for
     overstated stranded costs twice: first through increased stranded
     cost charges and again through higher market prices. 
               The OCA asserts that GSEC's customers should pay no
     more than $30 million for stranded cost recovery, the pre-divestiture level of stranded costs, according to Dr. Rosen's
     calculations.  Dr. Rosen estimates that post-divestiture stranded
     costs for GSEC are $38 million to $40 million, $17 million to $19
     million less than the Settlement would allow GSEC to collect. 
     The OCA urges the Commission to eliminate GSEC's portion of the
     mitigation incentive payment.  The OCA also states that GSEC has
     not acted prudently in its obligation to mitigate stranded costs
     or it would not have agreed to the instant termination of its
     wholesale power agreement with NEP and thus exposed its customers
     to nuclear related costs as contained in the Settlement.  Brief
     at 13.         
          C.   Staff
     Distribution Surcharge        
               Mr. Cunningham recommends that the Commission approve
     GSEC's Pilot Program expenses for years 1996 and 1997 and those
     restructuring related costs incurred in 1997.  Mr. Cunningham
     would remove all 1998 costs from the Distribution Surcharge until
     they are actually incurred and recorded by the Company.  The 1998
     costs related to the Pilot Program and restructuring would then
     be recoverable, pending review by Commission auditors.  Ex. 26. 
     Transition Service
               Mr. McCluskey believes that the backstop provision in
     the NEP/USGenNE sale creates benefits for GSEC's customers, but
     that it is also anti-competitive.  He urges the Commission to
     eliminate the anti-competitive effects of the backstop provision. 
     Specifically, GSEC should purchase backstop power from USGenNE
     whenever the winning bid, which GSEC will utilize to acquire
     transition service power, is equal to or greater than the
     backstop price.  GSEC would then resell the power back into the
     wholesale market and credit any profits against stranded costs. 
     Mr. McCluskey believes this adjustment would allow transition
     service to function as it was intended.  Customers served under
     transition service would pay market-based prices for power and
     all customers would benefit through the reduction in stranded
               Mr. McCluskey bases his last point on the reduced sales
     value of the asset transfer to USGenNE as testified to by
     Mr. Levitan on behalf of Enron in the transfer docket, DE 97-251. 
     All customers pay more due to the lower value of the sale and
     thus the higher level of stranded costs, but only transition
     service customers get the benefit of the below market price of
     USGenNE's backstopped prices of transition service.  Mr.
     McCluskey believes his amendment to the backstop provision would
     remove the subsidy which flows to transition service customers
     under the Offer.  If the winning bid prices for transition are
     below the backstop prices in the Offer, then USGenNE would
     deliver any power to transition service customers. 
                    Mr. McCluskey also comments on the effect of the
     reduced sales value of the asset transfer due to USGenNE's
     backstop obligations in Massachusetts and Rhode Island.  He notes
     that Mr. Jasanis testified in DE 97-251 that the bid submitted by
     USGenNE did not provide for backstop service to GSEC, but that a
     backstop option for GSEC could be purchased for approximately
     $6.5 million on a present value basis.  In Mr. McCluskey's view,
     the additional cost of securing transition service for GSEC's
     customers should be shared by all NEP's customers.  GSEC's
     customers, therefore, would pay no more than their allocated 3
     percent share of the additional cost. 
               Mr. McCluskey also urges the Commission to enforce its
     policy to prohibit distribution companies from administering
     transition service and to eliminate the revenue loss adjustment. 
     The revenue loss adjustment allows NEP to sell transition service
     possibly at prices below its variable costs without suffering
     losses.  In Mr. McCluskey's view, the revenue loss adjustment
     would harm potential competitors.  
     Stranded Costs 
               Mr. McCluskey's main criticisms of the Settlement
     include: the Settlement is overly generous in its recovery of
     stranded costs by GSEC; the Settlement has been constructed in a
     way that shifts risks to customers; certain aspects of the
     Settlement are anti-competitive; and GSEC has not fulfilled its
     statutory obligation to maximize its mitigation of stranded
               Mr. McCluskey points out that the stranded costs in the
     Settlement consist of two sets of contract termination charges
     which NEP proposes to collect from GSEC.  Each set of contract
     termination charges includes fixed and variable components.  One
     set of contract termination charges is "pre-divestiture" of the
     pending NEP asset sale to USGenNE.  This pre-divestiture contract
     termination charge is intended to recover GSEC's allocated share
     of the book value of NEP's generating facilities and regulatory
     assets plus GSEC's share of certain variable costs of generation
     such as nuclear decommissioning, purchased power expenses, fuel
     transportation expenses, employee severance and retraining costs,
     and profits/losses associated with the sale of energy from NEP's
     nuclear entitlements.  The pre-divestiture recovery period begins
     July 1, 1998.  Fixed costs are recovered over 11.5 years with an
     11.18 percent pretax overall return and the variable component of
     the pre-divestiture contract termination charges are recovered
     through 2028.  Mr. McCluskey does not characterize the pre-divestiture stream of charges as stranded costs because they are
     intended to recover the full book value of NEP's generating
     assets without any recognition of the value of those assets.
               Post-divestiture stranded costs are reduced by the
     amount of GSEC's allocated share of NEP's proceeds from the non-nuclear asset sale to USGenNE.  Fixed cost recovery decreases to
     2 years from the pre-divesture 11.5 years and the variable cost
     component continues through 2028 but at a much lower level.  Mr.
     McCluskey estimates that GSEC is requesting stranded cost
     recovery of approximately $55 million (1998 dollars) if the sale
     of NEP's non-nuclear assets closes January 1, 1999.  Mr.
     McCluskey points out that his $55 million estimate of stranded
     cost recovery is higher than the LaCapra administrative stranded
     cost estimate of $49 million that the Commission adopted as part
     of its interim stranded cost charges in DR 96-150, Order
     No. 22,511.           
               Mr. McCluskey argues that the one-time mitigation
     incentive payable to NEP by GSEC of $3 million should be
     rejected.  The mitigation incentive fails to recognize GSEC's
     continued obligation to mitigate stranded costs and, in Mr.
     McCluskey's view, is not based on successful mitigation of
     stranded costs.  
     Return on Equity    
               Mr. Frantz and Mr. McCluskey both filed testimony
     concerning the 9.4 percent after-tax return on equity used to
     calculate GSEC's portion of NEP's post-divestiture stranded
     costs.  Due to the provision in the Settlement which allows NEP
     to adjust its contract termination charges based on changes in
     sales, the cost of debt, preferred stock, capital structure or
     income tax rates, Mr. Frantz believes NEP's financial risk is
     essentially eliminated.  Coupled with recovery of the post-divestiture fixed cost component of stranded costs over a two-year period or less, Mr. Frantz recommends that the rate of
     return on equity capital should reflect some risk premium, 50 to
     100 basis points, above the current yield on 2-year treasury
     notes.  Based on the 2-year treasury note yield of 5.5 percent,
     approximately, an appropriate equity return to apply to GSEC's
     post-divestiture stranded costs would be 6.0 percent to 6.5
     percent.  In Mr. Frantz's view, to allow a greater return  would
     provide a windfall to GSEC at the expense of GSEC's customers. 
               Mr. McCluskey also believes that NEP's business risk of
     not recovering its stranded costs is virtually eliminated under
     the Settlement, especially in light of the full reconciliation of
     actual sales to estimated sales and the prohibition against
     revisiting the justness and reasonableness of the stranded cost
     charges by FERC once FERC approves them.  Unlike Mr. Frantz, Mr.
     McCluskey would correct for the risk-reward mismatch by
     eliminating the reconciliation of revenues and stranded costs.
          Nuclear Cost Issues
               Mr. McCluskey opposes numerous aspects of the
     Settlement related to the recovery of nuclear costs, including
     the 80 percent/20 percent sharing mechanism between customers and
     NEP associated with the operation of NEP's nuclear entitlements
     during the period until NEP sells those assets.  He believes the
     mechanism favors NEP and shifts risks to customers because those
     assets are more likely to suffer losses than to earn profits.  He
     also asserts that NEP would make a double recovery of nuclear
     Public Policy Issues
               Mr. McCluskey raises a number of concerns about the
     Settlement's inclusion of public policy issues, especially the
     funding for conservation and load management (C&LM) and nuclear
     decommissioning.  In particular, Mr. McCluskey states that the
     Settlement provides for an average C&LM charge of 3.5 mils per
     kWh for five years which equates to an annual C&LM budget of
     between $2.53 million and $2.76 million.  Mr. McCluskey notes
     that a C&LM budget at those levels exceeds the $2 million budget
     approved by the Commission for GSEC in Order No. 22,818, a level
     agreed to in a settlement by the Company, CLF and Staff.  He also
     notes that the C&LM settlement provides for recovery of C&LM
     program planning, evaluation and administration costs that were 
     previously recovered through GSEC Purchased Power Adjustment
     Clause.  Those costs are estimated at $340,000 per year.  Mr.
     McCluskey recommends that GSEC be ordered to comply with the
     budget limitations agreed to in the settlement and approved by
     the Commission in Order No. 22,875.
               Mr. McCluskey urges the Commission to seek additional
     comment on the Settlement's proposal to use a 25-year Seabrook
     operating life for the purpose of calculating nuclear
     decommissioning costs.  He believes the proposed change cannot be
     adopted unless the Nuclear Decommissioning Finance Committee
     (NDFC) makes the same change for all joint owners of Seabrook.
          A.   Granite State Electric Company 
               The Company supports the Settlement as a final and
     comprehensive resolution of the numerous issues raised by
     electric restructuring.  The Settlement should be viewed in its
     entirety and weighed against the available alternatives: the
     May 1, 1998 Compliance filing and continued state and federal
     litigation.  Ex. 37, Arcate at 4,5.  In the Company's view, the
     Compliance filing is not as favorable to customers as the
     Settlement.  In support of the Settlement, the Company presented
     direct and rebuttal testimony on jurisdictional issues,
     transition service, stranded costs, post-divestiture return on
     equity, C&LM and decommissioning expenses. 
          B.   The Governor's Office of Energy and Community Services
               ECS states that the Settlement contains numerous
     benefits such as (1) the opening of the retail market in New
     Hampshire to competition in accordance with the time frame
     mandated by statute; (2) an immediate rate reduction of 10
     percent with another 7 percent to follow after divestiture; (3)
     predictable, competitively priced transition service in
     compliance with SB 341; (4) the end of the Company's litigation
     against the Commission; and (5) a commitment to environmental
     protections and public purpose programs.  Brief at 1,2. 
               ECS states that transition service should meet the
     following goals which are intended to protect consumers'
          1.   the option of stable and predictable generation prices
                    during the transition period;
          2.   guaranteed savings at the start of retail access for
                    customers who take transition service and a possibility
                    for additional savings from alternative competitive
          3.   equitable benefits to those who do not choose a
                    competitive supplier; and 
          4.   competitive transition service prices, if possible.                             
     Ex. 18 at 2,3.
               ECS believes the transition service proposal contained
     in the Settlement and as amended in Exhibit 50 meets the above
     goals.  ECS contends that the transition service proposal of Mr.
     McCluskey does not meet those goals and that his proposal would
     allow for cross-subsidization.  Ex. 18 at 3.  ECS states that a
     competitive market takes time to develop and notes that RSA 374-F:1,II recognizes the need for a transition to a competitive
     market.  Brief at 8.  Early market price fluctuations could be
     due to a number of factors such as tight capacity, or customer
     caution, or uncertainty.  The backstop provision enhances a
     smooth transition and shifts risks of high market prices to
     USGenNE during that period and away from GSEC's customers.  Tr.
     Day 2 at 165 in DE 97-251.  Brief at 8.  ECS disputes the claims
     of Mr. McCluskey and others that the proposed transition service
     and the prices contained in Exhibit 50 are anti-competitive. 
               ECS also disputes the positions and recommendations of
     Mr. McCluskey concerning C&LM.  ECS states that the 3.5 mils per
     kWh charge proposed in the Settlement is not an average C&LM
     charge, but an average systems benefits charge to be used for
     both C&LM and renewable energy related public purposes.  Ex. 18
     at 6.  ECS avers that even if the average charge were used solely
     for C&LM and increased GSEC's budget slightly, the Commission
     should still approve such an outcome in the context of a global
     restructuring settlement.  
          C.   Conservation Law Foundation
               CLF states that the average systems benefit charge of
     3.5 mils per kWh is fully consistent with RSA 374-F, provides for
     cost-effective DSM programs, provides for the possibility of
     renewable energy programs, does not provide for funding in excess
     of GSEC's existing budget levels for DSM, and, with the addition
     of the change in transition service as contained in Exhibit 50,
     should be approved in its entirety.   
          D.   Campaign for Ratepayer's Rights
               CRR supports the Settlement and states that the
     Settlement represents the best chance of implementing the
     policies set forth in RSA 374-F.  Ex. 10 at 2.  The Settlement
     offers two important benefits not found in Commission Order Nos.
     22,511 and 22,514: immediate rate reductions and increased and
     accelerated nuclear decommissioning funding for the Seabrook
     nuclear power plant. Ex. 10 at 2.  
               CRR rebutted Dr. Rosen's contention that the
     NEP/USGenNE sale should be rejected because it resulted in a low
     value which as a result insufficiently mitigated stranded costs.
     Ex. 12 at 3.  Dr. Rosen's position that a higher transition
     charge is needed to ensure competition gets started, thereby
     resulting in long-term customer savings, is opposed by CRR in
     favor of immediate savings.  
               As amended and filed on July 13, 1998, we find that the
     Restructuring Settlement Agreement (Amended Settlement) meets the
     public good standard in RSA 374:30 and is generally consistent
     with the restructuring policies in RSA 374-F, recently enacted SB
     341, and our previously issued restructuring orders.  Although we
     believe the Settlement was flawed in certain areas, our decision
     to approve the Amended Settlement derives from the overall
     outcome of the Amended Settlement which includes near-term rate
     relief, divestiture of the majority of NEP's non-nuclear assets
     resulting in reduced stranded costs and additional rate
     reductions, commencement of retail choice, the end of the
     Company's participation in litigation in federal district court,
     an appropriate balancing of the interests of customers and
     shareholders, and a transition service framework designed to
     balance customer interest in stable and predictable generation
     rates at the onset of retail choice without seriously restricting
     the development of a competitive retail electric market.  We have
     evaluated the Settlement and the Amended Settlement based on the
     specific requirements of RSA 374-F to determine whether the
     Amended Settlement is in the "public interest."  Recently enacted
     SB 341 has aided our analysis.  It states:
          [C]ircumstances beyond the control of the public
               utilities commission may delay implementation of
               electric utility restructuring and consumer choice
               beyond July 1, 1998.  Further delay will harm the
               state's economy and cause a continued burden on the
               state's citizens, commerce, and industry.  Delays
               resulting from court orders have heightened the need to
               consider negotiated settlements to expedite
               restructuring, near term rate relief for customers, and
               customer choice.   
     The Amended Settlement is a "negotiated settlement" not precluded
     by the June 5, 1998 injunction by Judge Lagueux of the Federal
     District Court which barred this Commission from
          requiring any plaintiff, including plaintiff/
               intervenors, to implement New Hampshire Revised
               Statutes Annotated 374-F in accordance with the ...
               Commission's orders issued in the Electric Utility
               Restructuring Docket No. DR 96-150, or requiring
               plaintiffs to take any action under those orders,
               including the filing of compliance plans.  
          The restraining order clearly allowed for voluntary filings:
          This order shall not preclude the defendants from
               considering or ruling upon voluntary filings made by
               the plaintiffs to implement New Hampshire Revised
               Statutes Annotated  374-F, including the filing of
               settlements or submission of compliance plans.
               Unencumbered by the Federal District Court's
     restraining order, we evaluated the Settlement and the Amended
     Settlement based on the guidance provided us by our Legislature
     and our previous decisions on restructuring.  Based on those
     previous decisions, we stated in our Oral Deliberations that we
     could not accept certain aspects of the Settlement: those
     concerning the post-divestiture equity component of stranded
     costs; the term of transition service; and funding for certain
     public programs related to energy efficiency and renewable
               The Amended Settlement adequately addresses our
     concerns and will meet the overall objectives of RSA 374-F and SB
     341.  We also emphasize that the high likelihood of the closure
     of the NEP/USGenNE transaction reduced a number of our concerns. 
     Many of the issues raised by Mr. McCluskey were serious concerns
     that the impending divestiture helped to resolve.  
               We discuss the Settlement and the Amended Settlement
               Before evaluating GSEC's proposed stranded cost charges
     in light of the statutory standards for recovery, we note that a
     disagreement exists among GSEC, the stipulating parties and
     others concerning the extent of this Commission's authority and
     jurisdiction to address that particular issue.  According to
     GSEC, we do not have the jurisdiction to set stranded cost
     charges to be collected by GSEC from its retail customers that
     differ from the rates, terms and conditions of the contract
     termination charges approved by FERC.  Staff and others point to
     the FERC's decision on March 14, 1998 in Docket No. ER98-1440-000
     (Central Vermont Public Service Company) and aver the opposite:
          GSEC's decision to terminate its wholesale requirements
               contract was not necessary to institute retail
               competition pursuant to RSA 374-F...[and] any stranded
               costs that NEPCo experiences as a result of the loss of
               GSEC's retail customers are retail stranded costs and
               are subject to this Commission's jurisdiction.  
     ECS observes that the Settlement was expressly structured to
     leave that question open and argues that the Commission should
     not waste administrative time on the issue. 
               We reject GSEC's claim that the Commission lacks the
     jurisdiction to set GSEC's retail stranded cost charges at levels
     which deviate from the stranded cost obligations voluntarily
     assumed by GSEC via the CTC.  As we noted in Order No. 22,986
     (July 22, 1998), utilities are obligated to evaluate all cost
     mitigation opportunities, including those associated with
     remaining in wholesale requirements contracts versus agreeing to
     the early termination of such contracts.  Even though FERC
     accepted the CTC filing prior to the hearing in this case, FERC's
     decision does not diminish our authority (and obligation) to
     evaluate GSEC's actions in light of traditional prudence
     principles as well as GSEC's ongoing obligation under RSA 374-F
     to take all reasonable measures to mitigate stranded costs.  In
     addition to the FERC's March 14, 1998 order in Docket No. ER98-1440-000, the jurisdictional demarcation was supported recently
     by FERC in a decision which clarified the respective roles of
     state and federal regulation in relation to wholesale purchased
     power contracts.  See Central Vermont Public Service Corporation,
     84 FERC  61,194 (August 21, 1998).         
               On a related point, we reject GSEC's argument that it
     was compelled to terminate its wholesale requirements contract
     before retail choice could be implemented in GSEC's service
     territory.  GSEC appears to mistakenly assume that the existence
     of wholesale contractual obligations prevents retail customers
     from choosing an alternative power supplier, a notion which FERC
     has rejected.  Central Vermont Public Service Corporation, 81
     FERC  61,336 at 62,543, n.15 (1997), order on reh'g, 84 FERC 
     61,295 (September 23, 1998).  Not only is it possible for retail
     access to co-exist with wholesale contract obligations, but such
     a course may actually maximize savings for retail customers.  See
     e.g., New Hampshire Electric Cooperative, Inc., DR 98-097.
     Stranded Costs
               We are required by RSA 374-F, XII(a) to determine
     whether the stranded cost recovery we approve is equitable,
     appropriate, balanced and in the public interest.  We must
     balance the interests of customers with those of shareholders. 
               The Settlement provides for full and final resolution
     of GSEC's stranded costs.  GSEC states that its stranded costs
     are due to the early termination of its wholesale all-requirements contract with NEP.  Ex. 1A.  The Company asks us to
     focus on the post-divestiture period because it simplifies the
     issues, provides significant mitigation of stranded cost
     recovery, results in lower stranded cost charges in the first two
     years than were reflected in the Commission's interim stranded
     cost charges in DR 96-150, and substantially meets the
     requirements of RSA 374-F.  Brief at 7.  
               Others, such as Staff and the OCA, aver that stranded
     costs post-divestiture provide for more than full stranded cost
     recovery and do not, therefore, meet the equitable, appropriate
     and balanced standard required by RSA 374-F:3, XII(a).  Staff's
     main concerns focus on the pre-divestiture period, but Staff
     disputes the Company's claim that the sale of NEP's non-nuclear
     assets reduces stranded costs by 57 percent; rejects the
     Company's claim that it was ordered by the Commission to
     terminate the wholesale contract; contends that GSEC failed to
     defend its customers interests; criticizes various aspects
     related to the recovery of costs associated with NEP's nuclear
     assets; and recommend that the Commission reject or modify the
     portions of the post-divestiture contract termination charges
     related to return on equity and the mitigation incentive.  Staff
     Brief, pp. 11-20. 
               OCA's witness, Dr. Rosen, proposes that we use his
     estimate of market prices to administratively determine the value
     of stranded costs which he proposes we true-up every two years. 
     Tr., Day 3, pp. 52-54,69.  Dr. Rosen's analysis involves
     projections of revenues and costs 23 years into the future.  He
     calculates NEP's post-divestiture stranded costs at $360 million,
     in present value dollars.  
               We have carefully evaluated the Company's request for
     stranded cost recovery and the resulting contract termination
     charges.  As we stated in our Oral Deliberations, we would
     approve the stranded cost portion of the Settlement if two
     modifications were made.  These modifications related to the
     mitigation incentive and the return on equity which are addressed
     later in our analysis. We also stated that, in light of recent
     FERC decisions, we believe the stranded cost recovery included in
     the Settlement (and the Amended Settlement) is quite favorable to
     NEP.  Our view has not changed.  Our approval of the Amended
     Settlement which adjusts stranded costs based on our Oral
     Deliberations is premised on our support for market
     determinations of stranded costs, not administrative ones, and
     the overall level of rates resulting from the Amended Settlement,
     a level we believe results in the equitable, appropriate, and
     balanced requirements of RSA 374-F:4,V.  Our concerns about
     additional costs associated with NEP's nuclear entitlements are
     addressed below.         
     Return on Equity
               The Settlement provides NEP with the authorization to
     earn an overall pre-tax return of 11.18 percent, including a
     return on equity of 9.4 percent on substantially all of the
     unamortized assets and balances in the contract termination
     charge.  Ex. 1A at 48,115.  NEP's overall pre-tax return is
     capped at 11.18 percent, provided that the yield on 10-year
     Treasury constant maturities does not exceed 9 percent.  If the
     Treasury yield exceeds 9 percent, the overall return of 11.18
     percent will be adjusted to include NEP's actual cost of debt and
     preferred stock using a 9.4 percent equity return as described in
     Ex. 1A, Appendix 2 (Post-divestiture), page 13 of 24.
               GSEC and NEP support the return on equity for a number
     of reasons, including that it is below: NEP's currently
     authorized return on equity of 11.25 percent, GSEC's currently
     authorized return on equity of 10.00 percent, the return on
     equity of 10.2 percent that the Commission adopted for
     distribution assets in our Rehearing Order, Order No. 22,875, and
     the return on equity last approved by the Commission (Connecticut
     Valley Electric Company, Docket No. DR 96-170, Order No. 22,537
     (March 31, 1997)).  GSEC states that the 9.4 percent return on
     equity is designed to work with the incentive mechanism so when
     combined they result in a return
          that is consistent with traditionally allowed equity
               returns only if NEP's mitigation efforts are successful
               and customer savings are realized, while protecting the
               financial integrity of the Company (NEP) if the sale to
               USGenNE is not approved and stranded costs are not
               reduced as much as we expect."  
          Ex. 37, Kenney at 5.
               Two of Staff's witnesses argue that the formula for the
     contract termination charge changes the risk allocation between
     customers and shareholders because it fully reconciles revenues
     and costs.  Mr. Frantz points out those annual adjustments
     include changes in sales, cost of debt, preferred stock, capital
     structure and income taxes.  Mr. Frantz states that the Company's
     arguments concerning historical returns at the FERC or the equity
     returns authorized by this Commission for distribution electric
     companies are irrelevant to this determination.  He suggests that
     NEP's risk and therefore its return more closely resemble that of
     short-term treasury securities.  He recommends a return on equity
     based on a two-year treasury bill with a risk premium of 50 to
     100 basis points.  Mr. McCluskey points out that customers in
     California have experienced benefits of rate reduction bonds
     yielding 6.5 percent with guarantees no less than contained in
     the Offer of Settlement.  Mr. McCluskey believes the risk-reward
     mismatch could be rectified by eliminating the reconciliation of
     stranded costs and revenues.          
               As we stated in our Oral Deliberations, we could not
     accept the Settlement with the return on equity proposed by the
     Sponsors in the calculation of stranded costs, post-divestiture,
     given the low degree of risk and we would amend the return on
     equity on New England Power Company's post-divestiture stranded
     costs.  Having considered all the arguments, we find convincing
     Staff's testimony regarding the inappropriateness of the proposed
     return on equity based on the risks NEP would face post-divestiture.  We agree with Mr. Frantz that it would be
     unreasonable to authorize a 9.4 percent return on equity for what
     we consider to be a very low risk investment.  
               The Company's support for a higher return based on
     previous FERC authorized returns or returns authorized by this
     Commission are virtually meaningless with regard to the present
     determination.  The return on equity should reflect investor
     risk.  The record in this proceeding indicates that those risks
     are more closely associated with short-term treasury bills or the
     revenue reduction bond yields in California.  We indicated in our
     Oral Deliberations that we would adopt Mr. Frantz's
     recommendation of 6.5 percent which is based on a 100 basis point
     risk premium adjustment to a two-year Treasury bill.  We find
     that result reasonable based on the record before us. 
               The Amended Settlement, Appendix 2 (Post-divestiture),
     reflects the change in the return on equity to the overall
     capital structure.  The overall pre-tax return of 8.68 percent is
     used for purposes of calculating NEP's Contract Termination
     Charge and is, therefore, approved by the Commission.
     Mitigation Incentive Payment
               In our Oral Deliberations, we stated that we would
     modify that portion of the stranded cost formula in the
     Settlement which allows NEP to receive a stranded cost mitigation
     "incentive payment".  Under this risk/reward sharing mechanism,
     NEP must reduce the present value of the contract termination
     charges to GSEC from $130 million to $94 million before NEP
     becomes eligible for an incentive.  The $130 million assumes no
     mitigation.  Ex. 37, Kenney, p. 5.  If additional savings below
     the $94 million level are achieved, NEP is allowed to retain 10
     percent of those savings on stranded costs up to a cap of $3
     million.  The mitigation incentive payment is intended to work
     with the return on equity and would increase NEP's equity return
     by 1.6 percent, approximately.  Ex. 37, Kenney at 4,5.  
               We stated in our Oral Deliberations that it would be
     inappropriate for GSEC's customers to make this "incentive
     payment" in light of the fact that it was negotiated after the
     results of the USGenNE sale were known and GSEC's share of
     stranded costs was established.  We agreed with Mr. McCluskey
     that an incentive payment should be linked to future cost
     mitigation.  The incentive proposed in the Offer of Settlement
     was not.  For those reasons, we could not approve a payment which
     served no useful purpose and only added to the costs of GSEC's
     customers unnecessarily. 
               GSEC has removed the mitigation incentive payment in
     its Amended Settlement, a change we support for the reasons
     stated above.   
          Transition Service
               Much of the contention surrounding this proceeding
     centers on Transition Service.  The Settlement included a
     transition period beginning on July 1, 1998 and ending June 30,
     2002.  Transition Service would be made available to all
     customers of record as of the Retail Access Date, with additional
     provisions for certain small commercial customers and all
     residential customers after the Retail Access Date.  GSEC will
     arrange to competitively procure Transition Service and the
     backstop prices of USGenNE will serve as a ceiling price for
     those customers who avail themselves of Transition Service.  As
     contained in Attachment 7 to the Settlement, the prices are
     subject to a Fuel Price Adjustment Index and residential
     customers' Transition Service prices are subject to an inflation
               During the proceeding, GSEC introduced into evidence as
     Exhibit 50 its Proposal to Resolve Transition Service Issues.
     Exhibit 50 applies to the period after divestiture only if
     bidding for transition service "does not result in prices equal
     to or lower than the backstop service provided by USGenNE."   In
     the event that competitive suppliers do not offer to provide
     Transition Service at prices at or below the USGenNE backstop
     prices, the Transition Service prices will include a 3 mil per
     kWh adder to induce retail competition.  The 3 mil adder is based
     on an assumption that 100 percent of its retail customers remain
     on Transition Service.  The additional revenue from the 3 mil
     adder will be used to offset stranded cost recovery for all
     customers.  If customers leave Transition Service, GSEC will not
     receive the additional 3 mil adder assumed in the rate design and
     will recover the resulting under-recovery from any fuel and
     purchased power over-recovery remaining after divestiture. 
     Exhibit 50 also provides for a marketing and incentive program
     funded up to $100,000 to encourage customers to leave Transition
     Service if, two years after divestiture, less than 33 percent of
     GSEC's total retail energy sales have moved to the competitive
               Staff, Enron, RMA, OCA and Aalto oppose as anti-competitive the transition service provisions of the Settlement,
     particularly, the backstop provision and the term of transition
     service.  During the hearing, Mr. McCluskey and Dr. Rosen
     described alternatives to transition service which they contend
     would increase competition by eliminating or mitigating the
     effects of what they believe are the below market prices of the
     backstop provision.  Exhibit 55, depicting an alternative to that
     described in Exhibit 50, was proposed by Staff and others as a
     way to minimize the anti-competitive effects of Exhibit 50. 
               In our Oral Deliberations, we stated that we would
     accept Transition Service as contained in Exhibit 50 with some
     modifications.  Those modifications included a shorter transition
     period and that Transition Service be made available to all
     customers, not just the customers of record on the Retail Access
     Date.  We further stated that the prices in Exhibit 50 should
     work to complement the development of the market and that the
     additional 3 mil per kWh adder would not undercut the market. 
               Though we carefully considered the alternatives of Mr.
     McCluskey and Dr. Rosen, we find that the Transition Service
     proposal as filed in the Amended Settlement is consistent with
     our Oral Deliberations and the requirements of RSA 374-F:3, V(b). 
     Transition Service in the Amended Settlement will be
     competitively procured and available to all retail customers.  It
     will allow time for a transition to competition (RSA 374-F:1,II)
     while minimizing customer confusion and providing near-term rate
               The record clearly indicates a lack of competition,
     thus far, in Massachusetts and Rhode Island.  A long transition
     period coupled with low, perhaps below market, prices is no
     prescription for competition.  We are only too aware that the
     Transition Service of the Amended Settlement strays from our
     guidelines on Transition Service in our Rehearing Order, but we
     believe that  Exhibit 50 provides a fair compromise between
     stable and predictable rates and the development of the market if
     transition service bids fail to materialize.  Our ability to re-evaluate the market in the near future and determine whether to
     extend or terminate Transition Service on December 31, 2000,
     allays our concerns about the potentially below-market prices of
     the backstop provision.  
               The prices contained in Exhibit 55 would simply
     increase rates to customers who are not yet ready to make that
     choice.  We share the concerns of Mr. McCluskey and Dr. Rosen
     about the potentially anti-competitive effects of the backstop
     provision, and note that there is evidence in the record upon
     which to base those concerns.  However, we are persuaded that the
     3 mil per kWh adder contained in Exhibit 50 and our ability to
     re-evaluate the level of competition in the near future somewhat
     mitigate those concerns.  Finally, the staggered pace at which
     competition is occurring in New Hampshire provides some
     additional rationale that the Amended Settlement's Transition
     Service will offer customers some benefits without greatly
     compromising the benefits of competition.  
     Nuclear Costs
               NEP has indicated it will divest its nuclear assets,
     but that it is not in the customer's interest to do so at this
     time.  Under the Settlement, all past investment, post-shutdown,
     and nuclear decommissioning costs are fully recoverable through
     the contract termination charge. Ex. 37, Kenney at 13.  Until NEP
     can transfer its nuclear assets, NEP will implement a
     performance-based ratemaking (PBR) mechanism for its nuclear
     operating units.  Under the nuclear PBR, NEP agrees to assume 20
     percent of the incremental costs, including capital costs, and
     the revenues as part of its performance-based ratemaking
     mechanism.  The remaining 80 percent will be assumed by the
     retail customers of NEP's affiliated distribution companies.          Other parties, including Staff's Mr. McCluskey, oppose
     the nuclear PBR mechanism on the grounds that it shifts the
     operating risks of nuclear plants to customers and that the
     nuclear plants are more likely to lose money than to earn
     profits.  Ex. 29, p. 22,25.  NEP disagrees.  Ex. 37, Kenney, p.
     15.  NEP projects early year operating losses will be offset by
     profitable operations in later years.  In addition, the Company
     disagrees with other aspects of Mr. McCluskey's testimony,
     including his assertion that NEP will double recover certain
     nuclear costs.  Ex. 37, Kenney, p. 14.  
               We have carefully reviewed the nuclear cost issues and
     find that the circumstances of NEP's nuclear ownership are
     central to our approval of this segment of the Amended
     Settlement.  NEP's minority interest does not excuse it from
     taking all appropriate actions to minimize nuclear operating
     costs while ensuring safe plant operations.  The customers of
     GSEC should expect no less.  Nonetheless, small percentage
     ownership interests do affect a utility's ability to make
     significant operating or managerial changes.  We recognize this
     fact and we recognize NEP's commitment to sell its nuclear
     assets.  Ex. 1A, pp.16-19.  We will expect NEP to pursue
     aggressively a nuclear divestiture plan that maximizes, in a
     timely manner, stranded cost reduction.  Our review of NEP's sale
     of its nuclear assets will include a review of stranded costs
     consistent with the provisions of RSA 374-F:3,XII.    
               Until that divestiture occurs, we find the 80
     percent/20 percent sharing mechanism a reasonable way to share
     the operating risks and benefits of NEP's nuclear entitlements. 
     If NEP does not sell off its nuclear entitlements within a
     reasonable period of time, however, we will re-evaluate the PBR
               This is an area in the Settlement that clearly poses
     potential risks to customers.  We are aware that a proceeding
     before FERC is on-going concerning the recovery of certain costs
     associated with the early closure of Connecticut Yankee.  We will
     direct the Company to file a letter with this Commission
     indicating how it will respond if certain disallowances are made
     to the recovery of nuclear post-shutdown or replacement power
     costs based on an imprudence finding by FERC for those units in
     which NEP has a minority interest.  We do not expect the Company
     to pass on costs found imprudent to its customers.  
     Nuclear Decommissioning
               We believe it is appropriate to accelerate funding of
     NEP's portion of the expected Seabrook Unit 1 decommissioning
     expenses based on an assumed closure date of midyear 2015.  We
     recognize that sufficient nuclear decommissioning funding is
     highly dependent upon on a number of variables, including the
     type and age of plant, but we find the Settlement compelling and
     timely in regard to this issue as it pertains to NEP and GSEC's
     share of NEP's decommissioning costs.
               The Amended Settlement also includes, through the
     contract termination charge, the recovery of post-shutdown and
     nuclear decommissioning costs associated with NEP's minority
     interests in the following closed nuclear plants: Yankee Atomic,
     Maine Yankee, and Connecticut Yankee.  The Company supports these
     cost recoveries because closure of the plants was in the economic
     interest of customers.  The Company states that the expected
     shutdown costs are now even less than when the decision was made
     and that customers will receive any reductions in actual costs
     through the Reconciliation Account.  NEP owns minority interests
     in three other nuclear plants that are currently operating:
     Seabrook, Millstone 3 and Vermont Yankee.   
     Public Policy Issues
               The Settlement contained a number of concerns related
     to energy efficiency and environmental issues upon which we had
     previously provided policy guidance.  In particular, our March
     20, 1998, Rehearing Order reversed our directive that utilities
     phase-out their DSM programs over a two-year period.  We were
     persuaded instead to grant the request of some of the parties in
     DR 96-150 to convene a working group to address many of the
     complex issues concerning DSM or energy efficiency in a
     restructured electric environment.  Some of those same parties
     now would have us ignore our directives on rehearing or at least
     those with which they disagree.  Specifically, they seek through
     the Settlement a level of funding on average of 3.5 mils per kWh
     over a five-year period for energy efficiency programs and a
     renewable energy commercialization initiative, an initiative that
     could only be characterized as conceptual at this time.  
               We heard no compelling arguments to change our position
     as articulated in Order No. 22,875.  As we stated in our Oral
     Deliberations, we could not accept this part of the Settlement
     and would require that any changes to the Settlement reflect our
     previous decisions concerning energy efficiency and renewables.
     The Amended Settlement meets those criteria. 
     Other Issues
     Competitive Supplier Registration
               In the Plan, we established a rulemaking proceeding to
     address registration requirements for competitive suppliers of
     electric services.  Although initiated, the final supplier
     registration rules are not complete and we do not envision that
     these rules will be finalized and issued in the very near future. 
     Consequently, we have outlined temporary registration procedures
     in Attachment 1 of this order specifically for those suppliers
     selling in GSEC's franchise area.  
               The temporary procedures which we establish today also
     include consumer protection requirements with which competitive
     suppliers must comply.  While there are already several suppliers
     registered to sell to Retail Competition Pilot Program
     participants, the procedures being adopted in this Order differ
     significantly from those adopted in the Pilot Program.  Any Pilot
     Program supplier who wishes to provide competitive electric
     energy services to Granite State customers must re-register with
     the Commission before it can begin to market and sell to
     customers in GSEC's franchise area. 
                    In addition, we also attach the interim affiliate
     transaction guidelines which must be followed by GSEC and any
     affiliate selling unbundled electric energy products or services
     in GSEC's franchise territory.  As with the interim procedures
     governing supplier registration and consumer protection, these
     guidelines shall apply to GSEC and its affiliates in GSEC's
     service territory until final rules are issued.  
               Consistent with our decision on the New Hampshire
     Electric Cooperative's Electric Restructuring Settlement, an
     affiliate of a retail electric company which has not received
     approval from this Commission for its compliance filing or
     settlement may not participate in the retail market of GSEC. See
     Order No. 23,013 in DR 98-097 (September 8, 1998).  See also RSA
     374-F:4, IX.
     Low Income Energy Assistance
               In the Plan, we approved a level of funding for a low
     income energy assistance program and initiated the formation of a
     working group to assist us in the development of such a program. 
     The working group submitted its final report to the Commission on
     August 28, 1998.  The working group has recommended that until
     the Commission issues rules for a consistent statewide low income
     assistance program, the Commission consider and adopt, on a case
     by case basis, modified programs as may be proposed by individual
               In the Amended Settlement, GSEC agreed to file a low
     income discount rate in substitution of the percentage of income
     payment program being developed by the working group should that
     program not be approved and available at the time Granite State
     implements retail choice.  We remain committed to the development
     of a low income assistance program.  We believe that it will be
     less confusing to customers to see the systems benefit charge for
     such a program begin simultaneously with the implementation of
     retail choice than to see it as a new charge on their bill
     several months from now.  Consequently, we accept the Company's
     proposal and authorize it to begin collecting a systems benefit
     charge of 1.5 mils per kWh to fund a low income affordability
     credit with the understanding that the credit will be terminated
     once the Commission approves a statewide low income assistance
     program and the program is implemented.  We expect the Company to
     submit a filing for the interim affordability program for our
     review and approval before placing it into effect.  We will not
     authorize GSEC to provide a "safety net service" as a type of
     Default Service for low income customers as described in Section
     V, Low Income Protections.  We believe the prices contained in
     Transition Service coupled with the low income affordability
     program will provide those necessary protections.  We are
     concerned by GSEC's commitment to back the bad debt service for
     competitive electric suppliers of low income customers.  However,
     we will review any plan which is submitted.  
     Electronic Data Interchange
               We remind GSEC and potential electric suppliers that
     the report from the Electronic Data Interchange (EDI) working
     group will form the basis for EDI transactions until the EDI
     rulemaking is complete.  GSEC should also note that it must
     complete its EDI testing before it can test potential suppliers. 
     When GSEC has completed its own testing, it should inform the
     Commission.  GSEC should also inform the Commission when electric
     suppliers have met the EDI requirements.   
                    Based upon the foregoing, it is hereby 
               ORDERED, that the Amended Restructuring Settlement
     Agreement as filed by Granite State Electric Company and
     supported by the joint sponsors on July 13, 1998, is APPROVED
     consistent with the analysis set forth above; and it is
               FURTHER ORDERED, that the attachments to this order for
     supplier registration and affiliate transactions are adopted
     specifically as they apply to GSEC and its customers until such
     time that the Commission orders otherwise; and it is
               FURTHER ORDERED, that GSEC's bills reflect unbundled
     tariff elements as shown in Attachment 1 to the Offer Of
     Settlement which shall include separate line items for the
     following: Customer Charge, Distribution, Transmission, Stranded
     Cost Charge, Distribution Surcharge, Low Income Charge,
     Conservation and Load Management, and a Generation Charge
     reflecting either the transition service generation charge or the
     competitive generation charge, if appropriate; and it is   
               FURTHER ORDERED, that a docket be opened within the
     next 30 days to address the transmission issues raised by Mr.
                    By order of the Public Utilities Commission of New
     Hampshire this seventh day of October, 1998.
        Douglas L. Patch    Bruce B. Ellsworth        Susan S. Geiger
            Chairman           Commissioner            Commissioner
     Attested by:
     Thomas B. Getz
     Executive Director and Secretary
                                     ATTACHMENT 1
     DR 98-012                   
     Adopt Puc 2000 to read as follows:
          Puc 2001.01 Purpose.  
          (a)   The purpose of Puc 2000 is to establish requirements for
     competitive energy suppliers consistent with the promotion of full and
     fair competition among competitive energy suppliers.  
          (b)   Competitive energy suppliers shall:
               (1) Demonstrate a minimum level of financial resources and
                    the ability to provide customers with the level of service
                    they agree to purchase;
               (2) Engage in fair business practices and comply with all
                    applicable consumer protection laws and rules;
               (3) Disclose, and make available to the public, information
                    that will enable customers to make informed choices
                    regarding the supply of their power; and
               (4) Demonstrate they have qualified to do business and are
                    subject to service of process in New Hampshire.
          Puc 2001.02 Application of Rules.  Competitive energy suppliers
     and aggregators shall comply with Puc 2000.
     PART Puc 2002   DEFINITIONS
          Puc 2002.01 "Aggregate" means to combine the loads of multiple
          Puc 2002.02 "Aggregator" means any entity who aggregates
     electricity load and does not take ownership of the energy supplies
     needed to meet that aggregated load.
          Puc 2002.03  "Commission" means the New Hampshire public
     utilities commission.
          Puc 2002.04  "Competitive energy supplier" means any entity who
     sells or offers to sell electric energy service to retail customers.
          Puc 2002.05 "Electricity supply offer" means a solicitation to
     provide electric energy service tendered by a competitive energy
     supplier to a customer.
          Puc 2002.06  "Customer" means any person, firm, partnership,
     corporation, cooperative marketing association, tenant, governmental
     unit, or a subdivision of a municipality, or the state of New
     Hampshire who purchases retail electric generation supply from a
     competitive energy supplier.
          Puc 2002.07 "Established business relationship" means an existing
     relationship formed by a voluntary two-way communication between a
     competitive energy supplier and a residential or non-residential
     customer, with or without an exchange of consideration, on the basis
     of an inquiry, application, purchase, or transaction by the
     residential customer regarding products or services offered by the
     competitive energy supplier or aggregator.
          Puc 2002.08 "Small commercial customer" means any non-residential
     customer whose known or estimated maximum demand is less than or equal
     to 100 kilowatts.
          Puc 2002.09 "Telephone solicitation" means the initiation of a
     telephone call or message for the purpose of encouraging the purchase
     of a product or service, unless the call is made with the customer's
     express invitation or permission and the customer has an established
     business relationship with the caller.
          Puc 2003.01 Procedure for Registration.
          (a)   All competitive energy suppliers seeking to sell electric
     energy to retail customers in the state of New Hampshire shall file a
     registration application with the commission.
          (b) The registration application required by (a) above shall
     include, at a minimum, the following:
               (1) The legal name of the applicant as well as any trade
                    name(s) they intend to operate under; 
               (2) The applicant's New Hampshire business address and
                    principal place of business;
               (3) The names and business addresses of the applicant's
                    principal officers;  
               (4) The names of the applicant's affiliates and
               (5) Disclosure of any affiliate relationships and the nature
                    of any affiliate agreements with New Hampshire
                    jurisdictional electric distribution companies;
               (6) Telephone number of the customer service department or
                    the name, title and telephone number of the customer service
                    contact person;
               (7) Name, title and telephone number of the regulatory
                    contact person;
               (8) Name, title and telephone number of the registered agent
                    in New Hampshire for service of process; 
               (9) A copy of the applicant's authorization to do business
                    in New Hampshire from the secretary of state; 
               (10) Certification of compliance with independent system
                    operator reliability requirements;
               (11) Evidence of a minimum level of financial resources in
                    the name of the applicant and available for the New
                    Hampshire expenses of the applicant, on deposit in a New
                    Hampshire bank or financial institution, in an amount not
                    less than $20,000, in the form of:
                    a. Cash; or 
                    b.  A financial instrument showing evidence of liquid
                         funds, such as a certificate of deposit, an
                         irrevocable letter of credit, a line of credit, a loan
                         or a guarantee.
               (12) A listing and explanation of any proceedings where the
                    applicant or any of its principals, in the conduct of its
                    business within the past 5 years, have been or are currently
                    the subject of state or federal investigation or have had
                    its authority to do business revoked; 
               (13) Affidavit that the applicant agrees to comply with the
                    consumer protection requirements set forth in Puc 2004;
               (14) Verification of successful implementation of electronic
                    transaction capability with New Hampshire distribution
                    companies; and
               (15) Affidavit that the applicant: 
                    a.  Will obtain and maintain lists of consumers who
                         have requested being placed on a do-not-call list for
                         the purposes of telemarketing, including telephone
                         preference services lists maintained by the Direct
                         Marketing Association; 
                    b. Will not initiate calls to New Hampshire customers
                         who have requested being placed on do-not-call lists
                         and/or customers who are listed on the Direct
                         Marketing Association's telephone preference lists;
                    c.  Will obtain updated lists from the Direct
                         Marketing Association no less than semi-annually. 
          (b)  A $500 registration fee shall accompany each initial
          (c)  Competitive electric suppliers shall re-register with the
     commission annually.
          (d) Competitive electric suppliers shall submit to the commission
     the annual re-registration fee of $250.
          (d)   Based on a review of the completeness of the information
     provided in (a) above and the applicant's ability to demonstrate
     compliance with the requirements of Puc 2001.01(b), the commission
     shall make a determination regarding certification of an applicant's
     registration within 30 days of receipt of the application.  
          (e) Should the commission fail to make a determination within 30
     days of receipt of the application, the applicant shall be certified
     to provide electric generation supply until the commission completes
     its review.
          (f) If after the commission completes its review it finds that
     the application is not complete or the applicant failed to demonstrate
     an ability to comply with requirements of Puc 2001.01 (b), the
     certification to provide electric generation supply shall, once the
     commission complies with RSA 541-A:29, be revoked. 
          (g)   Any entity seeking to provide aggregation service to retail
     customers shall provide notification to the commission of their intent
     to do so.  
          (h) The notice of intent, required by (g) above, shall include,
     at a minimum, the following:
               (1) The legal name of the aggregator as well as any  trade
                    name(s) they intend to operate under;
               (2) The aggregator's business address and principal place of
               (3) The names and addresses of the aggregator's principal
               (4) The telephone number of the customer service contact
                    person; and
               (5) A copy of the aggregator's authorization to do business
                    in New Hampshire from the secretary of state.
          Puc 2004.01 Transfer of Service.
          (a)   Each competitive energy supplier seeking to provide a
     customer with electric energy service shall obtain valid authorization
     from the customer before providing such service.  
          (b)   Valid authorization, as described in (a) above, shall
     include written, verbal, faxed or electronic authorization. 
          (c)   Verbal authorization, pursuant to (b) above, must be
     verified by an independent third party for the authorization to be
     deemed valid.
          (d)  When a customer's request for a change in competitive energy
     suppliers is received over the telephone, the competitive energy
     supplier shall mail an information package to the customer within
     three working days of the customer's request.
          (e)  The information package, described in (d) above, shall
               (1) A statement that the information is being sent to
                    confirm the telemarketing order or verbal request; 
               (2) The name, address and telephone number of the newly-requested competitive energy supplier; 
               (3) The disclosure statement described in Puc 2004.02; and 
          (f) The written authorization form, required by (b) above, shall
               contain, at a minimum, the following:
               (1) The customer's billing name and address;
               (2) The account number(s) to be covered by the request for
                    change in competitive energy suppliers;
               (3) A statement that the customer has not initiated another
                    change in competitive energy suppliers within the current
                    billing period; and 
               (4) The customer's signature.
          (g) The authorization form shall be clearly identifiable and
     separate from any other marketing materials.
          (h) Upon receipt of valid authorization from the customer, the
     competitive energy supplier shall notify the distribution company
     electronically of the customer's request to switch competitive energy
          (i)  Competitive energy suppliers shall provide the distribution
     company with proof of valid authorization whenever requested by the
     distribution company. 
          (j)   The competitive energy supplier shall maintain records of
     authorization to switch service for a period of one year. 
     Puc 2004.02 Electricity Supply Offer Disclosure Requirements.
          (a)   The competitive energy supplier shall, prior to acceptance
     of any written or verbal electricity supply offer,  provide the
     customer a disclosure statement.
          (b) The disclosure statement required by (a) above shall contain,
     at a minimum, the following
               (1) All fixed and variable prices of the service being
                    offered including any penalties or fees for:
                    a.  Late payments; 
                    b.  Early termination of the electricity supply
                         agreement by the customer;  or 
                    c.  Any other penalties or fees.
               (2) The term of the competitive energy supplier's commitment
                    for price and terms and conditions;
               (3) The term of the customer's commitment to purchase from
                    the competitive energy supplier; 
               (4) A description of the competitive energy supplier's
                    dispute resolution process available to the customer if
                    dissatisfied with the service;
               (5) An explanation of how the customer will be billed for
                    generation service and the name and address of the
                    competitive energy supplier's billing agent, if any;
               (6) The competitive energy supplier's policy regarding
                    disclosure of customer usage, billing and payment
                    information; and 
               (7) The commission's toll free consumer affairs telephone
                    number and a statement that customers may contact the
                    commission if they have any questions about their rights and
          (b) When the electricity supply offer is made to the customer as
     part of a telephone solicitation, the competitive energy supplier, or
     its representative, shall disclose all of the information required in
     (b) above orally to the customer prior to the customer's acceptance of
     the offer in addition to providing written disclosure as  required in
     (b) above.
          Puc 2004.03 Bill Disclosure Information.
          (a)   The competitive energy supplier shall include on any bills
     which it issues or which are issued on its behalf, the following
               (1) The starting and ending date of the billing period;
               (2) Any fixed monthly charges;
               (3) The price structure for kilowatt hour use;
               (4) The prior meter reading; 
               (5) The current meter reading; 
               (6) The total kilowatt hours used during the billing period
                    which shall include for customers on a time-of-use or
                    similar pricing schedule, the total kilowatt hours used
                    broken down by time of use;
               (7) Any applicable penalty date and the related penalty;
               (8) Any other factors necessary to compute the charges;
               (9) An itemized breakdown of the charges, including any late
                    fee, penalty or aggregation fee if applicable;
               (10) The average price per kilowatt hour used during that
                    billing period; 
               (11) A statement that the customer has the right to  request
                    actual consumption information for each billing  period
                    during the prior year or the months therein during which the
                    competitive energy supplier provided the customer with
                    generation service; 
               (12) The telephone number of the supplier's customer service
                    department or customer service contact person; and
               (13) The toll free telephone number of the commission's
                    consumer affairs division.
          (b)   Upon request of a customer, competitive energy suppliers
     shall provide the customer with a clear and concise statement of the
     customer's actual consumption for each billing period during the prior
     year or the months therein which the competitive energy supplier
     provided the customer with generation service.
          Puc 2004.04 Notice of Termination of Service.  
          (a) Competitive energy suppliers shall provide 10 working days
     written notice to residential and small commercial customers prior to
     terminating the provision of generation service when the customer has
     failed to meet any of the terms of the agreement for service. 
          (b) Termination of service, which shall follow the notice period
     referred to in (a) above, shall be deferred until the later of the
     next meter reading date or the termination date specified on the
     notice to the customer. 
          (c)   Competitive energy suppliers shall provide 5 working days
     written notice to customers whose maximum demand exceeds 100 kilowatts
     prior to terminating the provision of generation service when the
     customer has failed to meet any of the terms of the agreement for
          (d) Competitive energy suppliers shall provide 2 working days
     electronic notice to the distribution company prior to terminating the
     provision of service to any customer who has failed to meet the terms
     of the agreement for service.
          (e)   While no authorization is required from the commission,
     competitive energy suppliers who decide to cease providing generation
     service within the state shall, prior to discontinuing service:
               (1) Provide sufficient electronic notice, which for the
                    purposes of this paragraph means the later of the starting
                    date of the next billing cycle or 30 calendar days from the
                    delivery of notice, to the distribution companies and
                    written notice to customers of the supplier's intent to
                    cease operations; and
               (2) Refund any outstanding customer deposits.  
          Puc 2004.05 Telephone Solicitation.
          (a)   No competitive energy supplier shall initiate any telephone
     call using an automatic telephone dialing system or an artificial or
     prerecorded voice unless the call is initiated for emergency purposes
     which, for the purposes of this section, shall be defined to mean any
     situation affecting the health and safety of customers.
          (b)   No competitive energy supplier shall initiate any telephone
     call to any of the following:
               (1) An emergency telephone line, including any 911 line or
                    any emergency line of a hospital, medical physician or
                    service office, health care facility, poison control center,
                    or fire protection or law enforcement agency; or 
               (2) The telephone line of any guest room or patient room of
                    a hospital, health care facility, elderly home, or similar
                    type establishment; or
               (3) A telephone number assigned to a paging service,
                    cellular telephone service, specialized mobile radio
                    service, or other radio common carrier service, or any
                    service for which the called party is charged for the call.
          (c)   No competitive energy supplier shall use a telephone
     facsimile machine, computer, or other device to send an unsolicited
     advertisement to a telephone facsimile machine.
          (d)   No competitive energy supplier shall initiate any telephone
     solicitation to a customer before 8:00 a.m or after 9:00 pm eastern
          (e)   The called party shall be provided with the name of the
     competitive energy supplier on whose behalf the call is being made as
     well as a telephone number or address at which the competitive energy
     supplier can be reached..
          (f)   No competitive energy supplier shall initiate any telephone
     solicitation to a  customer unless the competitive energy supplier has
     instituted procedures, as provided below, for maintaining a list of
     persons who do not wish to receive telephone solicitations made by or
     on behalf of that competitive energy supplier.
          (g) A competitive energy supplier shall implement procedures for
     telephone solicitation including: 
               (1) The competitive energy supplier must maintain a written
                    policy for maintaining a do-not-call list and make such
                    policy available to customers upon request;
               (2) Personnel engaged in any aspect of telephone
                    solicitation must be informed and trained in the existence
                    and use of the do-not-call list;
               (3) If a residential customer makes a request to be placed
                    on the do-not-call list, the request must be recorded at the
                    time it is made;
               (4) To protect the customer's privacy, the competitive
                    energy supplier must obtain prior express consent from the
                    customer before the customer's request to be placed on a
                    do-not-call list can be shared with or forwarded to a party
                    other than the competitive energy supplier on whose behalf
                    the solicitation is being made; and
               (5) Competitive energy suppliers must maintain do-not-call
                    lists for the purpose of any future telephone solicitations
                    and shall not contact customers on this list.
          (g) All competitive energy suppliers shall:
               (1)  Contact the Direct Marketing Association's Telephone
                    Preference Service and obtain a listing of New Hampshire
                    customers who have registered with that service prior to
                    conducting any telephone solicitations;
               (2)  Update its lists semi-annually from the Direct
                    Marketing Association's Telephone Preference Service
                    listings; and 
               (3)  Not make telephone solicitations to any customer who
                    has registered with that service or requested do-not-call
          (h) All competitive energy suppliers shall 
          Puc 2005.01 Investigation by the Commission.
          (a)   When a customer files a complaint with the commission's
     consumer affairs division, either orally or in writing, against a
     supplier alleging that the competitive energy supplier is not in
     compliance with the provisions of Puc 2000, the commission's consumer
     affairs division shall be authorized to begin an informal
          (b)   The competitive energy supplier shall provide any relevant
     information to the consumer assistance department which would assist
     the consumer assistance department in its efforts to investigate and
     resolve the dispute.  
          (c) If a competitive energy supplier feels the complaint does not
     constitute on its face a violation of Puc 2000 or applicable statues
     or administrative law,  it may request a hearing before the
          (d) If the commission determines the complaint on its face is
     warranted, the competitive energy supplier shall be required to
     provide any relevant information to the consumer affairs division
     which would assist it in its efforts to investigate and resolve the
          (e) The competitive energy supplier or the customer may request a
     hearing before the commission if dissatisfied with the resolution of
     the complaint.
          (f) The consumer affairs division shall request a hearing before
     the commission when it determines issues remain which require
     resolution by the commission. 
          (g)   Any information provided by the competitive energy supplier
     which the competitive energy supplier attests is commercially
     sensitive and meets one of the criteria for confidential information
     set forth in Puc 204.08(b) shall be treated confidentially in
     accordance with Puc 204.08(c).
          (h)   During a two year interim period which begins on the date
     that competition is implemented in one or more areas of the state, the
     commission shall also mediate and resolve disputes which are outside
     the purview of Part Puc 2003 and 2004.
          (i)   The commission shall, pursuant to RSA 374-F:9,III, fine a
     competitive energy supplier for any of the following:
               (1) Failure to register with the commission as required in
                    Puc 2003.01; 
               (2) A violation of any one of the provisions of Puc 2004; or
               (3) Any similar circumstances consistent with (1) and (2)
          (j)   The commission shall, pursuant to RSA 374-F:9,III, revoke a
     competitive energy supplier's registration for:
               (1) Willful misrepresentation of any of the information
                    required by 2003.01; 
               (2) Repeated violations of any one of the provisions of Part
                (3) Widespread systematic market abuses which violate any
                    of the provisions of Part Puc 2004; or
                (4) Any similar circumstances consistent with (1) through
                    (3) above..
                           ATTACHMENT 2
                            DR 98-012
     PART Puc    2101 DEFINITIONS  
     Puc  2101.01    "Affiliate" means any person, corporation, utility, partnership, or other entity 5
               per cent or more of whose outstanding securities are owned, controlled, or held with power
               to vote, directly or indirectly either by a utility or any of its subsidiaries, or by that utility's
               controlling corporation and/or any of its subsidiaries as well as any company in which the
               utility, its controlling corporation, or any of the utility's affiliates exert substantial control
               over the operation of the company and/or indirectly have substantial financial interests in
               the company exercised through means other than ownership.
     Puc  2101.02    "Commission" means the New Hampshire Public Utilities Commission.
     Puc  2101.03    "Customer" means any person or corporation that is the ultimate consumer of
               goods and services.
     Puc  2101.04    "Customer information" means non-public information and data specific to a
               utility customer which the utility acquired or developed in the course of its provision of
               utility services.
     Puc  2101.05    "FERC" means the Federal Energy Regulatory Commission.
     Puc  2101.06    "Fully Loaded Cost" means the direct cost of a good or service plus all
               applicable indirect charges and overheads.
     Puc  2101.07    "Subsidiary" means a company or entity owned and controlled by a utility, the
               revenues and expenses of which are subject to regulation by the Commission and are
               included by the Commission in establishing rates for the utility.
     Puc  2101.08    "Utility" means any public utility as defined in RSA 362:2 which provides or is
               involved in the provision of electric service ultimately sold to the public or competitive
               electric suppliers.
     Puc  2102.01   Applicability of Rules.
          (a)  Puc 2100 shall apply to:
               (1)  Public utilities, as defined in RSA 362:2, which provide electrical
               (2)  Affiliated competitive suppliers; 
               (3)  All utility transactions with affiliates that provide a product that uses
                    electricity or provides services that relate to the use of electricity, unless
                    specifically exempted; and 
               (4)  Transactions between a Commission-regulated utility and another
                    affiliated utility, unless specifically modified by the Commission in addressing a
                    separate application to merge or otherwise conduct joint ventures related to
                    regulated services.           
          (b)  Existing Commission rules for each utility and its parent holding company shall
     continue to apply except to the extent they conflict with Puc 2100, in which cases Puc 2100 shall
     supersede prior rules.
          (c)  Nothing in this chapter shall preclude:
               (1)  The Commission from adopting other utility-specific guidelines; or 
               (2)  A utility or its parent holding company from adopting other utility-specific
                    guidelines, with advance Commission approval.
     Puc  2102.02   Affiliate Entities and Transactions Described.
          (a)  "Substantial control", as used in the definition of affiliate in Puc 2101.01, shall
     include, but shall not be limited to, the possession, directly or indirectly and whether acting alone
     or in conjunction with others, of the authority to direct or cause the direction of the management
     or policies of a company.  
          (b)  A direct or indirect voting interest of 5% or more by the utility in an entity's
     company shall create a rebuttable presumption of substantial control sufficient to characterize the
     company as an affiliate of the utility.
          (c)  For purposes of Puc 2100, "affiliate" shall include the utility's parent or holding
     company, or any company which directly or indirectly owns, controls, or holds the power to vote
     10% or more of the outstanding voting securities of a utility or its holding company, to the extent
     the holding company is engaged in the provision of products or services as described in Puc
          (d)  In its compliance plan filed pursuant to Puc 2106, the utility shall demonstrate
     both the specific mechanism and procedures that the utility and holding company have in place
     to assure that the utility is not utilizing the holding company or any of its affiliates not covered
     by Puc 2100 as a conduit to circumvent Puc 2100 in any manner, including but not limited to
     those described in (e) below.  
          (e)  The utility shall demonstrate in its compliance plan, as described in (d) above,
     specific mechanisms and procedures to assure the Commission that the utility will not use the
     holding company or any another utility affiliate not covered by Puc 2106 as a vehicle to:
               (1)  Disseminate information transferred to them by the utility to an affiliate
                    covered by Puc 2100 in contravention of Puc 2100;
               (2)  Provide services to its affiliates covered by Puc 2100 in contravention of
                    Puc 2100; or
               (3)  Transfer employees to its affiliates covered by Puc 2100 in contravention
                    of Puc 2100.  
          (f)  In the compliance plan, a corporate officer from the utility and holding company
     shall verify the adequacy of the specific mechanisms and procedures described in the compliance
     plan to ensure that the utility is not utilizing the holding company or any of its affiliates not
     covered by Puc 2100 as a conduit to circumvent Puc 2100 in any manner.
          (g)  Subsidiaries of a utility are not included within the definition of affiliate.  
          (h)  Puc 2100 shall apply to all interactions any regulated subsidiary has with other
     affiliated entities covered by Puc 2100.
          (i)  Puc 2100 shall not preclude or stay any form of civil relief, or rights or defenses
     thereto, that may be available under state or federal law.
          (j)  A Commission-jurisdictional utility may apply to be exempt from Puc 2100 by
     filing a written request with the Commission requesting exemption as provided in (k) and (l)
          (k)  The utility shall file its request for exemption from this part as follows:     
               (1)  The utility shall file the letter within 30 days after the effective date of Puc
                    2100; and
               (2)  The utility shall simultaneously serve a copy of its letter on all members of
                    the service list of this rulemaking proceeding.
          (l)  The utility shall, in its written request pursuant to (g) above,:
               (1)  Attest that no affiliate of the utility provides services as described in Puc
                    2102.01(a)(3) above; and
               (2)  Attest that if an affiliate is subsequently created which provides services as
                    described in Puc 2102.01(a)(3), then the utility shall:
                    a.   Notify the Commission, by means of a letter to the executive
                         director and secretary with a copy served on all parties to this rulemaking
                         docket, at least 30 days before the affiliate begins to provide services as
                         described in Puc 2102.01(a)(3), giving notice that such an affiliate has
                         been created; and
                    b.   Include in this notice an affirmation by the affiliate agreeing to
                         comply with all applicable Commission rules.
          (m)  A New Hampshire utility which is also a multi-state utility and which is subject to
     the jurisdiction of other state regulatory commissions, may file with the Commission an
     application for a limited exemption from Puc 2100 or a part thereof, served on all entities on the
     service list of this rulemaking docket as provided in (n) and (o) below.
          (n)  A multi-state utility may file for an exemption for transactions conducted between
     the utility solely in its capacity serving its jurisdictional areas wholly outside of New Hampshire,
     and its affiliates.  
          (o)  The applicant has the burden of proof in an application for exemption pursuant to
     (h) and (j) above.
          (p)  Puc 2100 shall be interpreted broadly, to effectuate our stated objectives of
     fostering competition and protecting consumer interests.  
          (q)  If any provision of Puc 2100, or the application thereof to any person, company,
     or circumstance, is held invalid, the remainder of Puc 2100, or the application of such provision
     to other persons, companies, or circumstances, shall not be affected thereby.
     Puc  2103.01   No Preferential Treatment.    
          (a)  Unless otherwise authorized by the Commission or the FERC, or permitted by
     Puc 2100, a utility shall not:
               (1)  Represent that, as a result of the affiliation with the utility, its affiliates or
                    customers of its affiliates shall receive any different treatment by the utility than
                    the treatment the utility provides to other, unaffiliated companies or their
                    customers; or
               (2)  Provide its affiliates, or customers of its affiliates, any preference,
                    including but not limited to preferences in terms, conditions, pricing, or timing,
                    over non-affiliated suppliers or their customers in the provision of services
                    provided by the utility.
     Puc  2103.02   Affiliate Transactions.
          (a)  Transactions between a utility and its affiliates shall be limited to tariffed products
     and services, the sale or purchase of goods, property, products or services made generally
     available by the utility or an affiliate to all market participants through an open, competitive
     bidding process, or as provided for in Puc 2105.02 and Puc 2105.03 regarding joint purchases
     and corporate support, and Puc 2107 regarding new products and services provided the
     transactions provided for in Puc 2103 comply with the provisions of Puc 2000, titled Supplier
     Registration Rules, and Puc 2100.
          (b)  Except as provided for in Puc 2105, and Puc 2107, provided the transactions
     provided for in Puc 2107 comply with Puc 2100, a utility shall provide access to utility
     information or services, on the same terms for all similarly situated market participants.  
          (c)  If a utility provides services or information to its affiliate(s), it shall
     contemporaneously make the offering available to all similarly situated market participants,
     which include all competitors serving the same market as the utility's affiliates.
          (d)  Except when made generally available by the utility through an open, competitive
     bidding process, if a utility offers a discount or waives all or any part of any other charge or fee
     to its affiliates, or offers a discount or waiver for a transaction in which its affiliates are involved,
     the utility shall contemporaneously make such discount or waiver available to all similarly
     situated market participants.  
          (e)  The utilities should not use the "similarly situated" qualification, as used in (d)
     above, to create such a unique discount arrangement with their affiliates such that no competitor
     could be considered similarly situated.  
          (f)  All competitors serving the same market as the utility's affiliates should be
     offered the same discount as the discount received by the affiliates.  
          (g)  A utility shall document the cost differential underlying the discount to its
     affiliates in the affiliate discount report described in (n) and (o) below.
          (h)  If a tariff provision allows for discretion in its application, a utility shall apply that
     tariff provision in the same manner to its affiliates and other market participants and their
     respective customers.
          (i)  If a utility has no discretion in the application of a tariff provision, the utility shall
     strictly enforce that tariff provision.
          (j)  A utility shall process requests for similar services provided by the utility in the
     same manner and within the same time for its affiliates and for all other market participants and
     their respective customers.
          (k)  A utility shall not condition or otherwise tie the provision of any services
     provided by the utility, nor the availability of discounts of rates or other charges or fees, rebates,
     or waivers of terms and conditions of any services provided by the utility, to the taking of any
     goods or services from its affiliates.
          (l)  A utility shall not assign customers to which it currently provides services to any
     of its affiliates, whether by default, direct assignment, option or by any other means, unless that
     means is equally available to all competitors.
          (m)  Except as otherwise provided in Puc 2100, a utility shall not:
               (1)  Provide leads to its affiliates;
               (2)  Solicit business on behalf of its affiliates;
               (3)  Acquire information on behalf of or to provide to its affiliates;
               (4)  Share market analysis reports or any other types of proprietary or non-publicly available reports, including but not limited to market, forecast, planning
                    or strategic reports, with its affiliates;
               (5)  Request authorization from its customers to pass on customer information
                    exclusively to its affiliates;
               (6)  Give the appearance that the utility speaks on behalf of its affiliates or that
                    the customer will receive preferential treatment as a consequence of conducting
                    business with the affiliates; or
               (7)  Give any appearance that the affiliate speaks on behalf of the utility.
          (n)  If a utility provides its affiliates a discount, rebate, or other waiver of any charge
     or fee associated with services provided by the utility, the utility shall, within 24 hours of the
     time at which the service provided by the utility is so provided, post a notice on its electronic
     bulletin board reporting this information.
          (o)  To provide notice of the discount offering as described in (n) above, the utility
     shall post the following information on its electronic bulletin board:
               (1)  The name of the affiliate involved in the transaction;
               (2)  The rate charged;
               (3)  The maximum rate;
               (4)  The time period for which the discount or waiver applies;
               (5)  The quantities involved in the transaction;
               (6)  The delivery points involved in the transaction;
               (7)  Any conditions or requirements applicable to the discount or waiver;  
               (8)  A documentation of the cost differential underlying the discount as
                    required in (d) above; and
               (9)  Procedures by which a nonaffiliated entity may request a comparable
          (p)  A utility that provides an affiliate a discounted rate, rebate, or other waiver of a
     charge or fee associated with services provided by the utility shall maintain, for each billing
     period, the following information:
               (1)  The name of the entity being provided services provided by the utility in
                    the transaction;
               (2)  The affiliate's role in the transaction, such as shipper, marketer, supplier,
                    or seller;
               (3)  The duration of the discount or waiver;
               (4)  The maximum rate;
               (5)  The rate or fee actually charged during the billing period; and
               (6)  The quantity of products or services scheduled at the discounted rate
                    during the billing period for each delivery point.
          (q)  All records maintained pursuant to Puc 2100 shall also conform to FERC rules
     where applicable.
     Puc  2104.01   Customer Information.
          (a)  A utility shall provide customer information to its affiliates and unaffiliated
     entities on a strictly non-discriminatory basis, and only with prior affirmative customer consent.
          (b)  A utility shall make non-customer specific non-public information, including but
     not limited to information about a utility's electricity purchases, sales, or operations or about the
     utility's  electricity-related goods or services, available to the utility's affiliates only if the utility
     makes that information contemporaneously available to all other service providers on the same
     terms and conditions, and keeps the information open to public inspection.  
          (c)  Unless otherwise provided by Puc 2100, a utility continues to be bound by all
     Commission-adopted pricing and reporting guidelines for such transactions.  
     Puc  2104.02   Service Provider Information.
          (a)  Except as otherwise authorized by the Commission and pursuant to a request by a
     customer, a utility shall not provide its customers with any list of service providers, which
     includes or identifies the utility's affiliates, regardless of whether such list also includes or
     identifies the names of unaffiliated entities.
          (b)  If a customer requests information about any affiliated service provider, the utility
     shall provide a list of all providers of electricity-related, or other utility-related goods and
     services operating in its service territory, including its affiliates. 
          (c)  Any service provider may request that it be included on such list, and, barring
     Commission direction, the utility shall honor such request.  
          (d)  Where maintenance of such list would be unduly burdensome due to the number
     of service providers, subject to Commission approval, the utility shall:
               (1)  Direct the customer to a generally available listing of service providers,
                    such as, for example the Yellow Pages ; and
               (2)  Shall not be required to provide a list.
          (e)  The list of service providers provided shall make clear that the Commission does
     not guarantee the financial stability or service quality of the service providers listed by the act of
     approving this list.
     Puc  2104.04   Supplier Information.  
          (a)  A utility may provide non-public information and data which has been received
     from unaffiliated suppliers to its affiliates or non-affiliated entities only if the utility first obtains
     written affirmative authorization to do so from the supplier.  
          (b)  A utility shall not actively solicit the release of such information exclusively to its
     own affiliate in an effort to keep such information from other unaffiliated entities.
          (c)  Except as otherwise provided in Puc 2100, a utility shall not offer or provide
     customers advice or assistance with regard to its affiliates or other service providers.
          (d)  A utility shall maintain contemporaneous records documenting all tariffed and
     non-tariffed transactions with its affiliates, including but not limited to, all waivers of tariff or
     contract provisions and all discounts.  
          (e)  A utility shall maintain the records required by (d) above for a minimum of three
     years and longer if this Commission in other rules or another government agency so requires.  
          (f)  The utility shall make such records available for third party review upon 72 hours'
     notice, or at a time mutually agreeable to the utility and third party.
          (g)  A utility shall maintain a record of all contracts and related bids for the provision
     of work, products or services to and from the utility to its affiliates for no less than a period of
     three years, and longer if this Commission or another government agency otherwise so requires.
          (h)  To the extent that reporting rules imposed by the FERC require more detailed
     information or more expeditious reporting, nothing in these Rules shall be construed as
     modifying the FERC rules.
     PART Puc  2105 SEPARATION
     Puc  2105.01   Corporate Entities.  
          (a)  A utility and its affiliates shall be separate corporate entities.
          (b)  A utility and its affiliates shall keep separate books and records.
          (c)  Utility books and records shall be kept in accordance with applicable Uniform
     System of Accounts (USOA) and Generally Accepted Accounting Procedures (GAAP).
          (d)  The books and records of affiliates shall be open for examination by the
          (e)  A utility shall not share office space, office equipment, services, and systems with
     its affiliates, nor shall a utility access the computer or information systems of its affiliates or
     allow its affiliates to access its computer or information systems, except to the extent appropriate
     to perform shared corporate support functions permitted under Puc 2105.  
          (f)  Physical separation required by this section shall be accomplished preferably by
     having office space in a separate building, or, in the alternative, through the use of separate
     elevator banks and/or security-controlled access.  
          (g)  This section does not preclude a utility from offering a joint service provided this
     service is authorized by the Commission and is available to all non-affiliated service providers on
     the same terms and conditions.
     Puc  2105.02   Joint Purchases.
          (a)  To the extent not precluded by any other Commission rule, the utilities and their
     affiliates may make joint purchases of goods and services, but not those associated with the
     traditional utility merchant function.  
          (b)  For purpose of this section, to the extent that a utility is engaged in the marketing
     of the commodity of electricity to customers, as opposed to the marketing of transmission and
     distribution services, it is engaging in merchant functions.  
          (c)  Examples of permissible joint purchases include joint purchases of office supplies
     and telephone services.  Examples of joint purchases not permitted include electric power
     purchases for resale, purchasing of electric transmission, systems operations, and marketing.  
          (d)  The utility must insure that all joint purchases are priced, reported, and conducted
     in a manner that permits clear identification of the utility and affiliate portions of such purchases,
     and in accordance with applicable Commission allocation and reporting rules.
          (e)  As a general principle, a utility, its parent holding company, or a separate affiliate
     created solely to perform corporate support services may share with its affiliates joint corporate
     oversight, governance, support systems and personnel.  
          (f)  Any shared support shall be priced, reported and conducted in accordance with the
     Separation and Information Standards set forth herein, as well as other applicable Commission
     pricing and reporting requirements.
          (g)  As a general principle, such joint utilization shall not allow or provide a means for
     the transfer of confidential information from the utility to the affiliate, create the opportunity for
     preferential treatment or unfair competitive advantage, lead to customer confusion, or create
     significant opportunities for cross-subsidization of affiliates.
          (h)  In the compliance plan, a corporate officer from the utility and holding company
     shall verify the adequacy of the specific mechanisms and procedures in place to ensure the utility
     follows the mandates of this paragraph, and to ensure the utility is not utilizing joint corporate
     support services as a conduit to circumvent Puc 2100.
          (i)  Examples of services that may be shared include:  payroll, taxes, shareholder
     services, insurance, financial reporting, financial planning and analysis, corporate accounting,
     corporate security, human resources, including the compensation, benefits and employment
     policies functions, employee records, regulatory affairs, lobbying, legal, and pension
          (j)  Examples of services that may not be shared include: employee recruiting,
     engineering, hedging and financial derivatives and arbitrage services, purchasing for resale,
     purchasing of electric transmission, system operations, and marketing.
     Puc  2105.03   Corporate Identification and Advertising.
          (a)  A utility shall not trade upon, promote, or advertise its affiliate's affiliation with
     the utility, nor allow the utility name or logo to be used by the affiliate or in any material
     circulated by the affiliate, unless it discloses in plain legible or audible language, on the first page
     or at the first point where the utility name or logo appears that:
               (1)  The affiliate is not the same company as the utility;
               (2)  The affiliate is not regulated by the New Hampshire Public Utilities
                    Commission;  and
               (3)  A statement that, "you do not have to buy [the affiliate's] products in order
                    to continue to receive quality regulated services from the utility."
          (b)  The application of the name/logo disclaimer is limited to the use of the name or
     logo in New Hampshire.
          (c)  A utility, through action or words, shall not represent that, as a result of the
     affiliate's affiliation with the utility, its affiliates will receive any different treatment than other
     service providers.
          (d)  A utility shall not offer or provide to its affiliates advertising space in utility
     billing envelopes or any other form of utility customer written communication unless it provides
     access to all other unaffiliated service providers on the same terms and conditions.
          (e)  A utility shall not participate in joint advertising or joint marketing with its
          (f)  The prohibition on joint advertising and marketing means that utilities may
     engage or shall not engage, as described below, in activities, including but not limited to the
               (1)  A utility shall not participate with its affiliates in joint sales calls, through
                    joint call centers or otherwise, or joint proposals, including responses to requests
                    for proposals (RFPs), to existing or potential customers;  
               (2)  At a customer's unsolicited request, a utility may participate, on a
                    nondiscriminatory basis, in non-sales meetings with its affiliates or any other
                    market participant to discuss technical or operational subjects regarding the
                    utility's provision of transportation service to the customer;
               (3)  Except as otherwise provided for by Puc 2100, a utility shall not
                    participate in any joint activities with its affiliates, including but not limited to,
                    not participating jointly with any affiliate in advertising, sales, marketing,
                    communications and correspondence with any existing or potential customer; or
               (4)    A utility shall not participate with its affiliates in trade shows,
                    conferences, or other information or marketing events held in New Hampshire.
          (g)  A utility shall not share or subsidize costs, fees, or payments with its affiliates
     associated with research and development activities or investment in advanced technology
     Puc  2105.04   Employees.
          (a)  Except as otherwise permitted by these rules, a utility and its affiliates shall not
     jointly employ the same employees including members of the boards of directors and corporate
     officers, except as provided in below.
          (b)  The prohibition on a utility and its affiliate hiring joint employees shall not apply
     in the following circumstances:
          (c)  In instances when this Rule is applicable to holding companies, any board
     member or corporate officer may serve on the holding company and with either the utility or
     affiliate (but not both). 
          (d)  Where the utility is a multi-state utility, is not a member of a holding company
     structure, and assumes the corporate governance functions for the affiliates, the prohibition
     against any board member or corporate officer of the utility also serving as a board member or
     corporate officer of an affiliate shall only apply to affiliates that operate within New Hampshire.  
          (e)  In the case of shared directors and officers, a corporate officer from the utility and
     holding company shall verify in the utility's compliance plan the adequacy of the specific
     mechanisms and procedures in place to ensure that the utility is not utilizing shared officers and
     directors as a conduit to circumvent any provision of Puc 2100.
          (f)  All employee movement between a utility and its affiliates shall comply with the
     following provisions:
               (1)  A utility shall track and report to the Commission all employee movement
                    between the utility and affiliates;
               (2)  The utility shall file with the Commission annually its report on employee
                    movement between the utility and its affiliates;
               (3)  Once an employee of a utility becomes an employee of  an affiliate, the
                    employee shall not return to the utility for a period of one year;  
               (4)  The prohibition on returning to employment with the utility shall be
                    inapplicable if the affiliate to which the employee transfers goes out of business
                    during the one-year period;   
               (5)  In the event that an employee returns to the utility after being employed by
                    a affiliate, after a one year period, or shorter if the affiliate went out of business
                    during the one year period, such employee cannot later be retransferred to,
                    reassigned to, or otherwise employed by the affiliate for a period of two years;
               (6)  Employees transferring from the utility to the affiliate are expressly
                    prohibited from using information gained from the utility in a discriminatory or
                    exclusive fashion, to the benefit of the affiliate or to the detriment of other
                    unaffiliated service providers;
               (7)  When an employee of a utility is transferred, assigned, or otherwise
                    employed by the affiliate, the affiliate shall make a one-time payment to the utility
                    in an amount equivalent to 25% of the employee's base annual compensation,
                    unless the utility can demonstrate that some lesser percentage, which shall be
                    equal to at least 15%, is appropriate for the class of employee included; 
               (8)  All such fees as described in this paragraph paid to the utility shall be
                    accounted for by the utility in a separate memorandum account to track them for
                    future rate making treatment on an annual basis, or as otherwise necessary to
                    ensure that the utility's ratepayers receive the fees;  
               (9)  The transfer payment provision shall not apply to clerical workers or to the
                    initial transfer of employees to the utility's holding company to perform corporate
                    support functions or to a separate affiliate performing corporate support functions,
                    provided that that transfer is made during the initial implementation period of Puc
               (10) The transfer payment provision shall apply to any subsequent transfers or
                    assignments between a utility and its affiliates of all covered employees at a later
               (11) Any utility employee hired by an affiliate shall not remove or otherwise
                    provide information to the affiliate which the affiliate would otherwise be
                    precluded from having pursuant to Puc 2100; or
               (12) A utility shall not make temporary or intermittent assignments, or
                    rotations to its affiliates.
     Puc  2105.05   Transfer of Goods and Services.  
          (a)  To the extent that these Rules do not prohibit transfers of goods and services
     between a utility and its affiliates, all such transfers shall be subject to the following pricing
               (1)  Transfers from the utility to its affiliates of goods and services produced,
                    purchased or developed for sale on the open market by the utility shall be priced
                    at fair market value;
               (2)  Transfers from an affiliate to the utility of goods and services produced,
                    purchased or developed for sale on the open market by the affiliate shall be priced
                    at no more than fair market value;
               (3)  For goods or services for which the price is regulated by a state or federal
                    agency, that price shall be deemed to be the fair market value, except that in cases
                    where more than one state commission regulates the price of goods or services,
                    this Commission's pricing provisions govern;
               (4)  Goods and services produced, purchased or developed for sale on the open
                    market by the utility shall be provided to its affiliates and unaffiliated companies
                    on a nondiscriminatory basis, except as otherwise required or permitted by Puc
                    2100 or applicable law;
               (5)  Transfers from the utility to its affiliates of goods and services not
                    produced, purchased or developed for sale by the utility will be priced at fully
                    loaded cost plus 5% of direct labor cost; AND
               (6)  Transfers from an affiliate to the utility of goods and services not
                    produced, purchased or developed for sale by the affiliate will be priced at the
                    lower of fully loaded cost or fair market value.
     PART Puc  2106.01   Compliance Plans.
          (a)  Each utility shall include in its compliance filing a plan demonstrating to the
     Commission that there are adequate procedures in place that will preclude the sharing of
     information with its affiliates that is prohibited by Puc 2100. 
          (b)  Upon the creation of a new affiliate which is regulated by Puc 2100, the utility
     shall immediately notify the Commission of the creation of the new affiliate, as well as posting
     notice on its electronic bulletin board.  
          (c)  No later than 60 days after the creation of a new affiliate, the utility shall file an
     amended compliance plan with the Commission, with a copy served on members of the service
     lists to this rulemaking proceeding.  
          (d)  The amended plan described in this part shall demonstrate how the utility will
     implement and comply with the provisions of Puc 2100 with respect to the new affiliate.
     Puc  2106.02   Affiliate Audit. 
          (a)  No later than December 31 of each year, the utility shall have audits prepared by
     independent auditors that verify that the utility is in compliance with Puc 2100.  
          (b)  The utilities shall file this audit with the Commission no later than March 1 of the
     following year, and serve a copy of this audit on all members of the service list of this
     rulemaking proceeding. 
          (c)   The audits described in this section shall be prepared at shareholder expense and
     shall not be charged to ratepayers.
          (d)  Affiliate officers and employees shall be made available to testify before the
     Commission as necessary or required on all maters relating to audits or compliance plans,
     without subpoena.