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. I. INTRODUCTION AND SUMMARY 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) II. PROCEDURAL HISTORY 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 filing. 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. III. OFFER OF SETTLEMENT Introduction 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 Order. 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 customers. 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 Hampshire. 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 Distribution 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 customers. IV. POSITIONS OF NON-SIGNING PARTIES AND STAFF 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, VII. 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: YEAR Wholesale Price Cents/kWh Retail Adder Cents/kWh Market Price Retail Cent/kWh Exhibit #55 Prices 1998 3.55 1.2 4.75 4.0 1999 3.68 1.2 4.88 4.1 2000 3.78 1.2 4.98 4.2 2001 3.90 1.2 5.10 4.3 2002 4.20 1.2 5.40 4.4 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 classes. 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 costs. 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 costs. 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 costs. 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. V. POSITIONS OF THOSE PARTIES SPONSORING THE SETTLEMENT 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' interests: 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 suppliers; 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. VI. COMMISSION ANALYSIS 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 energy. 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 below. Jurisdiction 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 cap. 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 market. 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 relief. 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 mechanism. 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 utilities. 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. Rodier. 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 INTERIM PROCEDURES ESTABLISHING REGISTRATION REQUIREMENTS FOR COMPETITIVE ENERGY SUPPLIERS SERVING RETAIL CUSTOMERS OF GRANITE STATE ELECTRIC COMPANY Chapter Puc 2000 COMPETITIVE ENERGY SUPPLIER RULES Adopt Puc 2000 to read as follows: PART Puc 2001 PURPOSE AND APPLICATION OF RULES 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 customers. 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. PART Puc 2003 REGISTRATION REQUIREMENTS 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 subsidiaries; (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; and c. Will obtain updated lists from the Direct Marketing Association no less than semi-annually. (b) A $500 registration fee shall accompany each initial application. (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 business; (3) The names and addresses of the aggregator's principal officers; (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. PART Puc 2004 CONSUMER PROTECTION REQUIREMENTS 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 include: (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 suppliers. (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 information: (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 responsibilities. (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 information: (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 service. (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 time. (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 treatment. (h) All competitive energy suppliers shall PART Puc 2005 DISPUTE RESOLUTION PROCEDURES 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 investigation. (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 commission. (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 dispute. (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) above.. (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 2004; (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 INTERIM PROCEDURES GOVERNING TRANSACTIONS BETWEEN GRANITE STATE ELECTRIC COMPANY AND AFFILIATED COMPANIES 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. PART Puc 2101 APPLICABILITY OF RULES Puc 2102.01 Applicability of Rules. (a) Puc 2100 shall apply to: (1) Public utilities, as defined in RSA 362:2, which provide electrical services; (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 2100.03(b). (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) below. (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. PART Puc 2103 NONDISCRIMINATION 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 offer. (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. PART Puc 2104 DISCLOSURE AND INFORMATION 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 Commission. (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 management. (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 affiliates. (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 following: (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 research. 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 2100; (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 time; (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 provisions: (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 REGULATORY OVERSIGHT 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.