ML20203F947
| ML20203F947 | |
| Person / Time | |
|---|---|
| Site: | Seabrook  |
| Issue date: | 02/09/1999 |
| From: | AFFILIATION NOT ASSIGNED |
| To: | |
| Shared Package | |
| ML20203F941 | List: |
| References | |
| NUDOCS 9902190043 | |
| Download: ML20203F947 (180) | |
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{{#Wiki_filter:, y -. . .. - . - - . . . - - . - _ - _ _ ... . - . - - - l ! UNITED STATES OF AMERICA ! NUCLEAR REGULATION COMMISSION ! l In the Matter of ) North Atlantic Energy Service Corporation ) Docket No. 50-443 ( l ! and Canal Electric Compa:y ) (License No. NPF-86) 4
) !'
l l Febmary 2,1999 ; i Re: Request for Commission Consent to the Indirect Transfer of Control of Interest in the Operating License l Identified Above.8 ! I. INTRODUCTION i 2 Canal Electric Company (" Canal"), for itself as a Joint Owner and a licensee of Seabrook Station, hereby requests that the Commission consent to the indirect transfer of i control of Canal's interest in Operating License No. NPF-86 (the "Seabrook Operating I l License") pursuant to Section 184' of the Atomic Energy Act of 1954, as amended (the "Act"), ! and 10 CFR 550.80. This request is being filed in connection with the proposed merger of l l
' This Request is being filed concurrently with a filing in Docket No. 50-293 that relates to the same transaction.
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.2 North Atlantic Energy Service Corporation (" North Atlantic") is the licensed operator l of Seabrook Unit No.1 and is also authorized to act as agent for the eleven owners of the l facility: North Atlantic Energy Corporation, Canal Electric Company, The Connecticut Light i and Power Company, Great Bay Power Corporation, Hudson Light & Power Ley.rtment,
( Massachusetts Municipal Wholesale Electric Company, Montaup Electric Company, New
- England Fower Company, New Hampshire Electric Cooperative, Inc., Taunton Municipal Light Plant and The United Illuminating Company (collectively referred to herein as the "Seabrook Joint Owners" or with North Atlantic the "Seabrook Licensees").
8 42 U.S.C. (2234.- a 3355 % 3.09 ? 9902190043 990211 - PDR ADOCK 05000443 P PDR_ ; i
y , m . I l l Canal's parent organization, Commonwealth Energy System ("CES"), with BEC Energy (the l l " Parent Merger"). l Tramartion
Background:
Canal is a wholly-owned subsidiary of Commonwealth l l t Energy System, a Massachusetts Business Trust organized under the laws of Massachusetts l ("CES"), and an exempt public utility holding company under Section 3(a)(1) of PUHCA. On December 5,1998 CES and BEC Energy, a Voluntary Association organized under the laws of i l j Massachusetts ("BEC")', entered into an Agreement and Plan of Merger pursuant to which l l those entities will merge into a new surviving Massachusetts corporation (the "New Company"). Upon consummation of the Parent Merger, the stockholders of CES and BEC l will become stockholders of New Company (with BEC stockholders owning approximately 68% of New Company and CES stockholders owning approximately 32%) and the assets (including their respective subsidiaries) and liabilities of BEC and CES will become assets and liabilities of New Company. Therefore, Canal will become a whcliy-owned subsidiary of New Company. Thus, the Parent Merger will effect an indirect change of control of Canal's interest in the Seabrook Operating License. Seabrook
Background:
. Seabrook Station Unit No.1 ("Seabrook Station") is a nuclear powered electric generating facility which is owned by the eleven Seabrook Joint l Owners pursuant to an Agreement for Joint Ownership, Construction and Operation of New , Hampshire Nuclear Units, dated May 1,1973, as amended (the " Joint Ownership ( l Agreement"), and is operated by North Atlantic pursuant to the Seabrook Operating License. I d BEC is the parent of Boston Edison Company, the licensed owne and operator of Pilgrim Nuclear Power Station, NRC Docket No. 50-293. 3355963 m ' 1
. 1 l I In accordance with the Joint Ownership Agreement and the Managing Agent Operating l
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Agreement, dated as of June 29,1992, as amended (the "MAOA"f, North Atlantic is the I J Managing Agent for the eleven Seabrook Joint Owners and as such has responsibility for the management, operation and maintenance of Seabrook Station. North Atlantic's position as Managing Agent and operator was approved by issuance of Amendment No.10, dated May 29,1992, to the Seabrook Operating License. Granting the request contained in this i submission will not in any way affect North Atlantic's position as Managing Agent and operator of Seabrook Station or its responsibilities under the MAOA or any technical aspects of the Seabrook Operating License. Canal is the successor in title to the interest in Seabrook Station originally acquired by one ofits affiliates and currently owns a 3.52317% interest in Seabrook Station. Since Canal is an electric utility, it was found by the Commission to be financially qualified without a financial review being required,' and Canal continues to be listed as one of the Seabrook Licensees identified in the Seabrook Operating License. Reenhearv Approvals. In addition to the consent of the Commission requested hereby, the proposed Parent Merger will require the regulatory approvals listed below. 5 A copy of the MAOA has been previously filed with the Commission in this docket as L part of the Application to Amend the Facility Operating License to Authorize Ne th Atlantic j Energy Service Corporation to Act as Managing Agert for Seabrook Station, dated November j 13,1990, t ! 6 See Amendment No. 5 to Construction Permit No. CPPR-135, dated June 23,1982, l i in the above docket. 3335963o , ; e I i' __ , - . . ., .l
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- 1. Massachusetts Denartment of Telecommunications and Energy ("MDTE"). Certain affiliates of Canal that provide retail electric public utility service under Massachusetts law' will file a rate plan for each affected utility company for approval by the MDTE under the provisions of M.G.L. c.164, it' order to receive the appropriate ratemaking treatment for certain of the transaction costs associated with the proposed Parent Merger.
- 2. Securities and Exchange Commission ("SEC"). A preliminary joint proxy statement will be filed by CES and BEC for approval of the merger transaction with the SEC, and a second filing will be made with the SEC seeking an exemption for the New Company under the provisions of the PUHCA.
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- 3. Federal Fnergy Regulatory Commission (""FERC"). An application will be filed pursuant to section 203 of the Federal Power Act for FERC approval of the Parent Merger.
- 4. Federal Trade Commission /Denartment of Justice. A letter regarding the merger transaction will be filed with the United States Federal Trade Commission and the United States Department of Justice pursuant to the H,.rt-Scott-Rodino Antitrust Improvements Act of 1976, as amended.
II. APPLICATION FOR CONSENT TO INDIRECT TRANSFER OF CONTROL. Pursuant to 10 CFR s50.80, Canal hereby requests that the Commission consent to the indirect transfer of control of Canal's interest in the Seabrook Operating License, which l 7 The affiliates of Canal that provide retail public utility service in Massachusetts are Cambridge Electric Light Company, Commonwealth Electric Company and Commonwealth Gas Company. l i sassuw> . . _.
indirect transfer of control will result from the implementation of the Parent Merger described l above. I Set forth below is the supporting information required by the Commission's j implementing regulation,10 CFR @50.80, for an application for consent to such an indirect l l transfer. 1.10 CFR 550.33 General Information: (a) Name of Licensee: Canal Electric Company will continue to be a Licensee under the Seabrook Operating License. (b) Address of Licensee: The current business address is One Main Street, Cambridge, MA 02142, until the Commission is otherwise notified in writing. (c) Description of Business: Canal is an electric utility corporation organized and operating under the laws of the Commonwealth of Massachusetts and is a wholly-owned subsidiary of CES. In addition, CES has three wholly-owned electric or gas distribution companies, Cambridge Electric Light Company, Commonwealth Electric Company (together, the " Distribution Affiliates") and Commonwealth Gas Company, (collectively with the Distribution Affiliates, the " Retail Subsidiaries", and with Canal, the "CES System"), with service territories in eastern Massachusetts. Canal has traditionally functioned as the generating company within the CES System, engaging in the purchase of electric power at wholesale and the generation of electric power which it has resold at wholesale to the Distribution Affiliates und::r contracts containing rates based upon cost-of-service approved by the Federal Energy Regulation Commission ("FERC"). The Distribution Affiliates and Canal 3355963 m _ - . .
hold valid franchises, permits and other rights which are necessary to allow these companies to l conduct an electric utility business within the territories they serve. i I (d) Cornorate Charter: (i) Canal is a corporation organized under the laws of the Commonwealth of - l Massachusetts with its principal place of business in Massachusetts. Its Articles of Organization and Bylaws will be provided upon request. They will not be changed in any way as a result of the Parent Merger. 1 (ii) The names and addresses of the directors and principal officers of Canal, all of whom are United States citizens, are as follows: DIRECTORS Name Business Address D. A. McLaughlin (1) J.D. Rappoli (1) M.P. Sullivan (1) J. R. Williams (1) R.D. Wright (1) (1) P.O.- Box 9150, Cambridge, MA 02142-9150 ! 1 i 1 I l l ! l.
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[ n559029 l l
L l l' I l l OFFICERS Iillt ' Name Address ! Chairman of the Board and Chief Executive Officer R.D. Wright (1) President and Chief Operating Officer D.A. McLaughlin (1) ! Financial Vice President and i Treasurer J.D. Rappoli (1) i l Vice President, Clerk and l General Counsel M.P. Sullivan (1)
- l. Vice President-Customer Service C.W. Kiely (1) :
- Vice President-Energy Supply l and Engineering Services J.J. Keane (1)
Vice President-Operations K.F. Roberts (1) l Assistant Vice President - Administration T.M.X. Fontes (1) l Assistant Clerk R.J. Morrison (1) Assistant Clerk M.J. Doherty (1) i (1) P.0, Box 9150, Cambridge, MA 02142-9150 l (iii) Foreign Control: Canal is not now owned, controlled or dominated by an alien, foreign corporation or foreign government. After the merger, Canal will become a direct i subsidiary of the New Company which is not owned, controlled or dominated by an alien, ! foreign corporation or foreign government. , l (e) Agency Stanec: Canal is not acting as agent or representative of any other person. l ~(f) FinancialInformation: The information under clause (4) of 10 CFR Section 50.33 appears in Paragraph II.2(a) below. (g) Emergency Resnonse Plan: This section is not applicable to this Request. L k 3nm3o, lL l l-i.
, _ . - . - - - - . ~ . - (h) Construction or Alteration at Facility: This section is not applicable to this Request. (i) Regulatory Agencies and News Publications: The following regulatory agencies, in addition to the Commission, have financing, siting, or ratemaking jurisdiction over Canal: Massachusetts Department of Telecommunications and Energy l 100 Cambridge Street i Boston, MA 02202 ; j I l 1 Securities and Exchange Commission 1 450 Fifth Street, NW ! Washington, D.C. 20549
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l \ i Federal Energy Regulatory Commission J 888 First Street, NE Washington, D.C. 20426 l j l , The following publications circulate in the general area of Seabrook Station: 1 1 ; The Boston Globe P.O. Box 2378 l Boston, MA 02107 ) i l The Union Izader l P.O. Box 9555 Manchester, NH 03108 J
. (j) Restricted Data:
This request does not contain any Restricted Data or other defense information, and it is not expected that any such information will become involved in the licensed activities. 1 However, in the event such information does become involved, North Atlantic, as the representative of Canal, will appropriately safeguard such information and will not permit any l us5963 m l l l
- l individual to have access to Restricted Data until the Office of Personnel Management shall have made an investigation and reported to the Commission on the character, associations and loyalty of such individual, and the Commission shall have determined that permitting such person to have access to Restrictetl Data will not endanger the common defense and security of l the United States.
(k) Decommissionino: The information under this clause appears in Paragraph II 2(b) below.
- 2. 10 CFR 550.33 Financial Information:
(a) Financial Oualifications for Continued Conduct of Activities: Clause (f) of 10 CFR 550.33 exempts an electric utility from demonstrating its financial i qualifications. Canal currently is, and after implementation of the Parent Merger will continue to be, an " electric utility" as defined in 10 CFR 550.2. Chapter 164 of the Acts of 1997 (the
" Massachusetts Restructuring Act") established the framework to restructure the electric utility industry in Massachusetts. Having sold its fossil generating assets in compliance with the Massachusetts Restructuring Act, Canal's current business now involves the purchase of power at wholesale and the generation of power at Seabrook Station and sale at wholesale of such electric energy to the Distribution Affiliates under cost-of-service rates approved by FERC.
After implementation of the Parent Merger, Canal's contracts with the Distribution Affiliates will continue to be regulated by FERC. Therefore, Canal submits that it is exempted from the requirements of Clause (f) of 10 CFR 550.33. 1 3355 % 3 29 ~9"
Without waiving that exemption and to assist the Commission's evaluation of this Joint Request. Canal voluntarily submits the following information relating to its qualifications to continue funding its operational activities authorized by the Seabre t Operating Iicense. Canal specifically calls the Commission's attention to the fact that Ca aal recovers the full amount of costs billed to Canal associated with Seabrook Station operating costs from the Distribution Affiliates pursuant to the terms of a cost-of-service Power Contract between Canal and those Companies, dated September 1,1986, as amended, that is regulated by FERC. That Contract provides that, in consideration of the payment of those costs and Canal's share of other Seabrook Station charges, the Distribution Affiliates collectively purchase 100% of Canal's share of the capacity and energy generated at Seabrook Station. That Contract has been filed with the FERC. The Distribution Affiliates in turn recover those costs from their respective retail customers under rates subject to the jurisdiction of the MDTE. (b) Decommissioning Funding: Clause (k) of 10 CFR f50.33 requires an application for an operating license for a utilization facility to contain information indicating how reasonable assurance will be provided that funds will be available to decommission the facility. The Seabrook Licensees previously filed on December 27,1989, as updated on July 23, 1990, a Report demonstrating how such reasonable assurance would be provided by the Seabrook Licensees, including Canal. collectively. Canal has made all required payments into the Seabrook Decommissioning Trust Fund. After the Parent Merger is implemented, Canal J l will continue to make its ongoing payments to the Seabrook Decommissioning Trust Fund and l will continue to collect it's share of the Seabrook Station decommissioning and other post shutdown costs from the Distribution Affiliates pursuant to the terms of the aforesaid Power ) n55963m I , Contract between Canal and those Companies dated September 1,1986, as amended. The Distribution Affiliates in turn are assured of recovering 100% of the Seabrook decommissioning costs included in the payments due to Canal under that Contract from their respective retail customers under rates subject to the jurisdiction of the MDTE and approved in connection with the CES Electric Restructuring Plan (a copy of which is attached as Exhibit A 1
- hereto), which was approved by the MDTE on February 27,1998 in Docket No. DPU/DTE i
l 97-111 (a copy of which is attached as Exhibit B hereto). l [ l 3.10 CFR 550.34 Information: l I Clause (b)(7) of 10 CFR 550.34 requires information describing the technical 1 qualifications of the applicant to engage in the proposed activity. Pursuant to the MAOA, North Atlantic is the Managing Agent for the Seabrook Joint Owners and, as such, has responsibility for the management, operation and maintenance of Seabrook Station. North i Atlantic's technical qualifications were approved in connection with Amendment No.10 to the i .Seabrook Operating License in Docket No. 50-443. The Parent Merger wiin not affect the technical qualifications of North Atlantic nor involve any modification of North Atlantic's other responsibilities. Therefore, clause (b)(7) of 10 CFRl50.34 is not applicable. j i l 4.10 CFR 550.33a Information: ! 1 l CES has disposed of substantially all of its generation capacity as a result of the l Massachusetts Restructuring Act, except for the nuclear interest that is the subject of this j i { ! n55mm __ - ._ _- . .
1 l-I Request and other mi: lor interests.7 Furthermore, the indirect change of control involved herein does not represent a transfer to a new owner but only a corporate restructuring. Finally, Canal's interest in Seabrook Station amounts to only approximately 40MW and therefore l . constitutes a dc mmums interest. Therefore, no Section 105 antitmst review is required. III. CONCLUSION, Based upon the foregoing, Canal Electric Company hereby respectfully request that the Commission consent to the indirect transfers of control described in Section II hereof. As stated above, the proposed merger will require several different regulatory l approvals, the timing of which is difficult to predict. In order to facilitate completion of the merger, the undersigned respectfully request that the Commission act on this Request as promptly as possible and that the Commission provide that its Consent remain effective until at I least December 31,1999. ! CANAL ELECTRIC COMPANY l By . s Chairman of th oard and Chief Execut ve Officer 1 Commonwealth of Massachusetts ) 7 j The CES System still retains two generation facilities: the Blackstone Station in l- Cambridge, MA, and the MATEP plant in Boston, MA. 3353w3.o9 \ l l 1 :
I l Commonwealth of Massachusetts ) l County of Middlesex ) February 2,1999 l- ! Then personally appeared before me, Russell D. Wright, who being duly sworn, did ' state that he is Chairman of the Board and Chief Executive Officer of Canal Electric Company , l and that he is duly authorized to execute and file the subrnittal contained herein in the name l and on behalf of Canal Electric and that the statements herein attributable to Canal Electric l- Company are based on facts and circumstances which are true and accurate to the best of his t knowledge and belief. l , t ICb Y- offfs i Notary Public , l Richard J. Morrisola l My commission expires: September 23, 1999 1 l l l I i 1 i l l t U 335 m 3.m i I I i I
Shibif N
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! c, COMMONWEALTH OF MASSACHUSETTS DEPARTMENT OF PUBLIC UTILITIES
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Cambridge Electric Light Company / ) Commonwealth Electric Company / ) D.P.U. 97-Canal Electric Company )
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l l ELECTRIC RESTRUCTURING PLAN OF ! CAMBRIDGE ELECTRIC LIGHT COMPANY COMMONWEALTH ELECTRIC COMPANY AND I CANAL ELECTRIC COMPANY i L INTRODUCTION / OVERVIEW Cambridge Electric Light Company (" Cambridge"), Commonwecith Electric Company (" Commonwealth") and Canal Electric Company (" Canal"; collectively, the !
" Companies" or "COM/ Electric") file for approval with the Department of Public Utilities (the " Department") this electric restructuring plan (the " Plan"). The Plan offers the Companies' retail customers competitive electric generation service in a manner that complies with legislative mandates and the Department's restructuring policies set forth l
in D.P.U. 95-30 and D.P.U. 96-100. I Massachusetts has been a national leader in aggressively pursuing the restructuring of the electric industry. The Department began the effort in earnest over two years ago by opening a generic docket to explore altematives to traditional regulation of vertically integrated electric utilities. In Electric Industry Restructurine, D.P.U. 95-30 (1995), the Department indicated that each Massachusetts electric company should submit a proposal to move to a competitive generation market and to increase customer
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choice. The Department's subsequent rulemaking proceeding, Electric Industrv i Restructurine, D.P.U. 96-100 resulted in proposed rules. D.P.U. 96-100, Explanatory l Statement and Proposed Rules, May 1,1996. On December 30,1996, the Department is;ued a comprehensive plan for a restructured electric industry, including Model Rules and a legislative proposal. D.P.U. 96-100, Electric Industry Restructuring Plan, i December 30,1996. Several companies filed different proposals which subsequently led to the filing of settlements by three utility systems. On October 1,1996, Massachusetts Electric Company and Nantucket Electric Company ("MECo") filed a settlement resolving most issues relating to electric restructuring for those companies (the "MECo Settlement"). The MECo Settlement (as subsequently revised) was sponsored and endorsed by a wide range of stakeholders, representing all major interests. Signatories to the MECo Settlement included the Attorney General, the Division of Energy Resources, Low-Income Intervenors, large customer representatives, energy-efficiency and renewable-resource advocates and independent power producers. The MECo Settlement provided for, inter ali_a, the implementation of retail access to a fully competitive generation market, the divestiture of generation assets, standard offer service with a minimum 10 percent rate reduction and the recovery of all non-mitigated stranded costs through a transition charge. The MECo Settlement was initially approved by the Department on February 26,1997. Massachusetts Electric Comoany. D.P.U. 96-25 (1997). l Eastern Edison Company ("EECo") and Boston Edison Company ("BECo") have i filed restructuring plans with the Department. Those plans were endorsed by most of the l l
I a 1 { l l same partiespgenerally.
- follow the MECo settlement and each is awaiting a decision by !
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the Department (D.P.U. 96-24 and D.P.U. 96-23, respectively). l l Because the restructured electric industry envisioned by the Department and reflected in the settlements represent a major departure from the existing statutory l l framework,1997 has seen significant activity on the legislative front. On February 24, 1997, Govemor Weld filed legislation to establish a statutory framework for restructuring the electric industry, and to provide the Department with express authority to enact the i
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proposed Model Rules. Since then, legislation has proceeded through the General Court to implement electric restructuring, and it is clear that enabling legislation mandating retail choice on March 1,1998 will most likely be enacted imminently. Thus, in 1 accordance with the Department's directives and the pending statutory mandates, the Companies will be required to provide restructured electric service by March 1,1998. As described in more detail below, this Plan is intended to implement restructured service by such date and to provide sufficient time for the Department and interested 1 l persons to review and comment on the Companies' restructuring proposal. The Plan j comports with the Department's policies, is consistent with the plan approved for MECo l l (and those filed by EECo and BECo), and complies with the statutory requirements that will become effective upon er.actment of the pending legislation. The six basic elements of the Plan are as follows:
- 1. Retail Access to Generation Suppliers for all of the Companies' Retail Customers as of March 1,1998 Beginning on March 1,1998, all of the Companies' retail customers will be able to purchase electricity from alternative suppliers, es generators, marketers and e
l d 9 4 aggregators.,,The encouragement of a competitive, deregulated generation market is the major motivating policy of the restructuring effort. The Companies recognize that the ability of retail customers to gain access to the market in an efficient and effective manner is a necessary prerequisite to the development of a competitive retail generation market in Massachusetts. In addition to tariff changes to accommodate unbundled services,' the i implementation of retail choice requires the existing electric companies to alter l significantly their internal processes and information systems to provide the interface between the customer and the generation supplier. In the restructured environment, the 1 l traditional electric utilities will primarily provide only those services relating to the distribution and transmission of electricity.2 Consequently, entirely new systems are I needed to be put in place to provide information exchange between the distribution companies and suppliers. This includes, inter glia, protocols for customer enrollment, l l billing options, transfer of data, transfer of funds, release of customer information, and change in customer generation service.
- 2. Standard Offer Transition Service With a 10 Percent Rate Reduction !
to Retail Customers Who Do Not Immediately Choose to Purchase l From the Competitive Generation Market j l Although the development of a competitive generation market for electricity is the principal motivation for industry restructuring, it has been recognized that the successful l
' lilustrative tariffs for unbundled services are included in Exhibits I and 11, which also include documentation demonstrating the development of the revenue-neutral unbundling of existing rates.
2 Transitional mechanisms, such as Standard Offer Service, are addressed below. 1
i , 5-4 movement tq.a new market will require the presence of certain transition mechanisms to ensure that all customers are able to benefit immediately. The settlements filed to date and the pending legislation each mandate that customers who do not immediately choose to purchase generation from an altemative supplier have access, during a transition period, to Standard Offer Service that reflects a minimum 10 percent rate reduction. The Companies have included this required element in their Plan.' The price levels of the Companies' Standard Offer Service are identical to those filed with the other settlements for the seven-year period that it must be offered. The Companies are procuring such service through a competitive bidding process that will be subject to Department review and approval.
- 3. Mitigation of Transition Costs Through the Divestiture of Generation Resources The maximum mitigation of stranded costs requires electric companies to pursue all reasonable measures to minimize the amount of transition costs for customers.
Because the vast majority of the Companies' transition costs relate to payments to third parties under purchased power contracts approved by the Department and/or the Federal Energy Regulatory Commission ("FERC"), the Companies have, in the past, aggressively sought to reduce their obligations through a variety of means which are chronicled in Attachment 1 [ proprietary). To ensure that the remaining costs are minimized and that all residual value of the Companies' generating assets is credited to customers, the Companies have offered their generation assets to the market. The divestiture of 8 Exhibits 1.C and ll.C demonstrate that the new rates for customers choosing Standard Offer i Service reflect the 10 percent rate reduction. l
l , generation resources through a competitive market process will establish their market value and maximize transition cost mitigation. l l It should be noted that the Companies were the first utilities in Massachusetts to agree to divest their generation, and the auction process in which it is presently engaged is more comprehensive than any other Massachusetts electric company since it includes ! entitlements in purchased power contracts and nuclear generation. The solicitation i documents sent to prospective bidders are included as Attachments 2 and 3 [ proprietary).
- 4. Recovery of Transition Costs As was the case with the plans filed by other electric companies, the recovery of transition costs is through a non-bypassable transition cost charge that will be applied to all customers taking distribution service.' Transition costs can be placed into four general categories: (1) unrecovered fixed costs of generation units; (2) existing contractual cornmitments for purchased power (3) regulatory assets; and (4) nuclear decommissioning expenses. The amortization period proposed by the Companies reflects the 12-year period included in the approved MECo Settlement.' Purchased power expenses and nuclear decommissioning payments will be recovered over the term of the underlying obligations.
I l Exit fees to recover transition charges from customers who self-generate will be imposed to the extent permitted by law. The Con.canies expect that they will be submining for the Department's approval tariffs to collect such propued exit fees subsequent to the enactment of final legislation. I ' Consistent with the overall 10 percent rate eduction, the Companies' recovery of transition costs
- includes a 10 percent reduction on their return on equity for transition-related costs and deferrals.
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- 5. e Programs to Ensure Universal Service The Plan contains numerous provisions to ensure that electric service will be universally available to all of the Companies' customers in their service territories. As the ongoing provider of distribution and transmission services, the Companies will !
i maintain their traditional obligation to serve customers. The Companies' illustrative l Terms and Conditions for Distribution Service (in Exhibits I.A and II.A') incorporate all existing Department requirements regarding billing and termination, customer deposits, i payment of interest, etc. Low-income discounts will continue to be included in distribution rates, at levels comparable to those in existence today. In addition, the 1 l Companies address customer-protection issues relating to the restructured environment m 1 which customers will be able to make decisions with regard to their suppliers of i generation services. ! The Companies will also facilitate the transition to a competitive market and ensure that customers have access to continued, reasonably priced generation, by offering l i Standard Offer Service for the next seven years. For customers no longer entitled to l 1 Standard Offer Service, but without a competitive supplier, the Companies will arrange for Default Service at market prices. This will enable customers who have lost their I supplier to continue to be served. I
- 6. Energy Efficiency and Renewable Resource Programs Consistent with the existing settlements and the pending legislation, the Companies will fully comply with requirements to collect and expend funds to support
- The illustrative Tenns and Conditions for Distribution Service are consistent with the joint proposal made by the electric utilities in D.P.U. 97 65.
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energy-efficiency (including low-income) and renewable resource programs. For energy-efficiency programs, beginning March 1,1998 the Companies will collect and account separately for $0.0035 per kilowatthour for the remainder of calendar year 1998. The collection wiD be reduced each year until the year 2002, when it will equal $0.0025 per i l kilowatthour.' The Companies presently offer a wide range of energy efficiency 1 programs that are approved through June 30,1998 and are now engaged in a collaborative process relating to future program designs and annual budgets. The Companies intend to I l propose a detailed program for Department review and approval at the end of the collaboration, but in no event later than March 1,1998. In accordance with applicable i l l statutory requirements, the Companies will collect and distribute mandatory charges for l l renewable energy projects. l The remaining sections of the Plan provide more details about the provisions of i the Companies' restructuring proposal, including a discussion of the impact of the Plan on the Companies' employees and the communities served by the Companies. The Plan fully complies with the approved MECo Settlement, the other utility settlements, the Department's restructuring policies and the pending legislative mandates. I i 4 These levels of annual per kilowatthour collections would be adjusted to comply with applicable legislative mandates.
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e II. UNB,UNDLED RATES FOR RETAIL ACCESS A. Introduction The Companies have included as Exhibits I and II illustrative tariffs, supporting schedules and bill impact analyses for Cambridge and Commonwealth, respectively, that will implement retail choice on March 1,1998. Upon the Department's approval, actual compliance tariffs will be filed that would supersede existing rates and Terms and 1 Conditions presently in effect for the Companies' retail customers. ".nse tariffs would be submitted for effect on March 1,1998. The rates fully unbundle existing tariffs into generation, distribution / access ed . transmission components. The fuel charge is eliminated and Standard Offer Service and Default Service tariffs are available as optional supplier services for customers who do
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not purchase from competitive suppliers. The rate classes for the Companies are not being changed and the unbundling process is based on cost study methodologies most recently approved by the Department for the Companies. The development of the rates is described below.' B. Description of Unbundled Rates Effective March 1,1998 (the " Retail Access Date"), the Companies will knplement their unbundled retail delivery rates set forth in Exhibits I.A and II.A. The retail delivery rates set forth two categories of service for retail customers: Delivery Service and Supplier Service. Delivery Service includes three components: distribution charges, access charges and transmission charges. Supplier Services are optional and l The tariffs relating to Terms and Conditions, Standard Offer Service and Default Service are addressed in more detail in Section IV of the Plan.
c* , l- . include either, Standard Offer Service or Default Service. e, , I i The Companies will eliminate their current Fuel Charge, Conservation Charge
- and Energy Conservation Service Charge on the Retail Access Date. The Companies will add a Transmission Cost Adjustment and an Access Cost Adjustment to their delivery -
l service rates. The Delivery Service rates when combined with Standard Offer Service l prices are designed to result in total charges to customers that reflect a 10 percent discount from the total charges applicable to customers during August 1997. The Companies have designed their delivery service charges for low-income customers to l l retain the same level of discount on a percentage basis from the retail choice rates as is reflected in their existing low-income rates when compared to current undiscounted rates.
- 1. Distribution Charges Distribution charges will consist of customer, demand and energy charges as appropriate to recover the Companies' distribution costs, including costs formerly recovered under their Conservation Charge and Energy Services Conservation Charge.
The distribution charges are based on the existing separation of distribution and i transmission facilities on the Companies' systems, which is consistent with FERC's seven-part test for such separation. Sr.g Investication by the Deoartment into the Classification of Transmic ion and Distribution Facilities. D.P.U. 97-93 (September 23, i l 1997). The discount to low-income customers is maintained under the Companies' unbundled delivery service rates. To assure that the same level of discount is available ) [ regardless of the power supplier and to allow for the reconciliation of the transmission charges, the discount is applied exclusively to the distribution portion of the rate 1 (customer charges and distribution energy charges). d
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- 2. y Transmission Charces Transmission charges will be billed separately and will be subject to the ,
l Companies' Transmission Cost Adjustment. The Transmission Cost Adjustment will l l recover on a fully reconciling basis the transmission charges applicable to retail l 1 customers under the Companies' FERC-approved transmission tariffs. Such charges will j include the recovery of costs, if any, billed to the Companies associated with the Regional Transmission Group, an Independent System Operator or any other l transmission provider and which the Companies have authorization to recover from retail customers. The Transmission Ctsst Adjustment will be established annually based on the forecast of transmission costs, and will include a full reconciliation and adjustment for any over or under-recoveries occurring in the prior year's adjustment. The transmission l charge for each rate schedule will be se: initially based upon the allocated FERC transmission revenue requirement estimated for applicability on the Retail Access Date. Annual operation of the Transmission Cost Adjustment will determine changes from the i initial level of total revenue requirements. The changes in revenue requirement will be l 1 converted to a uniform $/kWh adjustment and applied to delivery service under each of the Companies' rate schedules.
- 3. Access Charces Access charges are designed to recover on a fully reconciling basis all of the Companies' transition costs. The access charges will be calculated on uniform cents per kilowatthour basis. The initial access charges are included in a combined distribution / access charge for recovery under Delivery Service and will be subject to
adjustment under the Companies' Access Cost Adjustment provisions. For each year, the t , Companies' uniform access charge will be calculated in accordance with the provisions in Exhibits 111 and IV. The changes in the uniform access charges from that calculated for i the initial year will be applied to customers through the Access Cost Adjustment.
- 4. Standard Qffer Service Standard Offer Service will be available for all retail customers on the Retail l Access Date. After the Retail Access Date, retail customers are free to leave Standard Offer Senice at any tin.t to purchase generation service from an altemative supplier. In i
general, once the retail customer has elected to receive senice from an altemate supplier, l the retail customer will not be allowed to retum to Standard Offer Service from the l Companies. However, the Companies' residential and G-1 customers who take service from a competitive supplier during the first year after the Retail Access Date may elect to return to Standard Offer Service within 90 days of taking altemative senice. In addition, any residential customer eligible for low-income rates or Default Senice may retum to Standard Offer Senice at any time. Further, any customer choosing to opt out from an authorized municipal or group aggregation program within 180 days folloving adoption of the program is eligible to receive Standard Offer Seavice, if originally enrolled in the Companies' Standard Offer Senice. The prices for Standard Offer Service are subject to adjustments as specified in the Standard Offer Senice Tariff. The charges for Standard Offer Service will appear separately on retail customers' bills. l l
l- -13 ' L -. ,
- 5. - g Default Service ;
Default Service will be provided to customers who have elected generation i i service from altemate suppliers, but who are currently without a contractual relationship . i l with any such supplier. Default Service is provided to maintain continuity of service for : 1 customers during the transition period when customers are making other supply i arrangements. The Companies will arrange for short-term wholesale power supply to , i provide this service on a cost pass through basis to retail customers. The prices for such i { service will reflect average wholesale power costs. j i
- 6. Termination ofTariffs l l
. The Fuel Charge and the Conservation Charge will be terminated and will apply - I i
to billings after the Retail Access Date only for usage occurring prior to the Retail Access j Date. - The final balances remaining after the Retail Access Date will be returned to or l collected from customers in the first quarter after the Retail Access Date. The Fuel l l Charge balance will not include any costs that are included in the Companies' calculation 1 of stranded costs. The recovery or retum of the balances decribed above will be subject to Department approval. C. Unbundled Rate Design for Commonwealth Electric Company ! Commonwealth based the design of its unbundled retail rates on billing l determinants, revenues and an allocated cost of service study for the year 1995. The 1995 l l revenue figures used in the rate design were adjusted to reflect the base rates, Fuel Charge l l and Conservation Charges applicable to customers bills in August l'97. The Fuel l c i Charge of $0.067 per kilov ahour includes $0.002 per kilowatthour to reflect the actual l_ level that the Fuel Charge would have been absent the restriction of such charge to $0.065
, . , , , - , - , s , - , - - ---
l 4 33
- 5. ,, Defaul tService Default Service will be provided to customers who have elected generation service from altemate suppliers, but who are currently without a contractual relationship with any such supplier. Default Service is provided to maintain continuity of service for customers during the transition period when customers are making other supply arrangements. The Companies will arrar.ge for short-term wholesale power supply to provide this service on a cost pass through basis to retail customers. The prices for such
^' service will reflect average wholesale power costs.
- 6. Termination of Tariffs
. The Fuel Charge and the Conservation Charge will be terminated and will apply to billings after the Retail Access Date only for usage occurring prior to the Retail Access Date. The final balances remaining after the Retail Access Date will be returned to or collected from customers in the first quarter after the Retail Access Date. The Fuel Charge balance will not include any costs that are included in the Companies' calculation of stranded costs. The recovery or retum of the balances described above will be subject to Department approval.
C. Unbundled Rate Design for Commonwealth Electric Company Commonwealth based the design of its unbundled retail rates on billing determinants, revenues and an allocated cost of service study for the year 1995. The 1995 revenue figures used in the rate design were adjusted to reflect the base rates, Fuel Charge and Conservation Charges applicable to customers bills in August 1997. The Fuel Charge of $0.067 per kilowatthour includes $0.002 per kilowatthour to reflect the actual level that the Fuel Charge would have been absent the restriction of such charge to $0.065
1 per kilowatth.our under Commonwealth's Fuel Charge Stabilization Agreement. Under this agreement, Commonwealth was allowed to increase its Fuel Charge to 50.067 per kilowatthour on January 1,1997. However, as a benefit to its customers, Commonwealth chose not to implement this increase at that time in contemplation of the advent of retail choice and the elimination ofits Fuel Charge. The Conservation Charges in effect for g each rate schedule at that time are listed in the table below. August 1997 Conservation Charces R-1, R-2, R-5, R-6 50 00083 per kilowatthour R-3, R-4 $0.00083 per kilowatthour G-1, G-4, G-7 $0.00179 per kilowatthour G-2, G-3, G-6, G-8 50.00247 per kilowatthour S-1, S-2, G-5, Contracts $0.00000 per kilowatthour The total revenues produced by reflecting the above-described charges were reduced by 10 percent resulting in the new revenue requirement. The 10 percent reduction was implemented by designing unbundled rates including Standard Offer Service that reflects 90 percent of the total: (i) per bill; (ii) per kilowatthour energy charges; and (iii) per kilowatt demand charges from the existing rates. This process assures that each customer bill under Standard Offer Service reflects 90 percent of the bill other . vise calculated using rates applicable during August 1997. The process used to unbundle Commonwealth's rates and revenues as described above into Distribution, Transmission, Generation and Access components started with Commonwealth's Functionalized Cost of Service Allocation Study ("COSS"). This cost study utilized methods for functionalization and allocation approved by the Department in Commonwealth's last rate proceeding, D.P.U. 90-331. The cost study first assigns all cost to functions including Generation, Transmission, Distribution and Customer
. componentscThe functional cost components for revenue requirem:nt and rate base are then allocated to rate classes. The COSS report is included as Exhibit :!.D.
The next step in the process is the determination ' he uniform $/kWh Access Charge applicable in the first year after the Retail Access Date. The unifonn Access Charge is determined by first replacing the generation component of the functional costs i with the Standard Offer Service price of 2.8 cents per kilowatthour. The difference l between 90 percent of the total revenue requirement based on August 1997 revenue levels and the sum of the Standard Offer Service, transmission,' distribution and customer l components determines the uniform access charge. This calculation produces a uniform i access charge of 4.26 cents /kWh. l The next step in the rate design process is to determine the design of individual unbundled rate schedules. Exhibits II.B sets forth the rate models used for developing the individual rates. Each of the rate models included in Exhibit II.B pertains to an individual rate schedule and includes the billing determinants and current revenue under existing rates, the functionalized COSS revenue requirements and the proposed unbundled rate prices. At the outset, the target for total revenues under the unbundled rate schedules is set at 90 percent of the existing total revenue level. The Standard Offer Service price is set at 2.8 cents /kWh, the uniform access charge is set at 4.26 cents /kWh and the transmission revenue requirement is set ficm the COSS information. The j; transmission charge is determined by unitizing the revenue requirement on the basis of j i l l i The functional costs were also adjusted to include the FERC-based transmission revenue
- requirement in place of the originally calculated transmission revenue requirement from the COSS. The FERC-based transmission revenue requirement was allocated to rate classes using the j same allocators that were used in the COSS.
J
I. . l either: (1) kWh, if the rate is non-demand billed; or (2) kW/kVa, if the rate is demand billed. The customer charge is set to 90 percent of the per-bill char",es under the existing rates. The remainder of the target revenue is used to design the d.stribution charges. If the rate includes demand charges, the distribution demand charf e is set at 90 percent of the existing demand charge, less the previously calculated tansmission demand charge; the distribution energy charge it calv.ilated to recover the remainder of the target revenue. i l If the rate does not include demand charges, the distribution energy charge is calculated directly to recover the remaining target revenue. If the rate design includes time-differentiated distribution energy charges, the energy charge for each time period is set
- such that the total energy charges for that time period equal 90 percent of the total energy j charges under the existing utes. Commonwealth's unbundled rate schedules reflect the combining of access charges with distribution charges.
This process yields unbundled rate designs which provide 10 percent discounts from existing rates for all customers. Commonwealth notes certain customers taking service at primary voltage 1-vels will generally receive discounts greater than 10 percent because the voltage discount 5 actors are applied to a greater base revenue level than under ; l existing rates. Commonwr;alth has provided typical bill comparisons for all rate schedules at Exhibit II.C. As of March 1,1998 Commonwealth will eliminate its present Large General Interruptible Service Rate, Large General Economic Development Rider, Large General Economic Development Rate (Closed), Service Extension Discount Rider, Vacant Space l Rider and Retail Choice Pilot Program. With the exception of the Interruptible rate, each of these existing rates provides a discount from Commonwealth's otherwise applicable 1
5 ,. base rate schydules. However, customer savings are preserved because Comn:onwealth's rates, which reflect a 10 pacent discount from total charges under current rates, govide customers on existing discount rates with a greater level of savings than the existing discounted rates. Since the Companies will no longer have generation assets or entitlements, interruptible customers will need to seek interruptible discounts from competitive power suppliers. D. Unbundled Rate Design for Cambridge Electric Light Company Cambridge also based the design of its unbundled retail rates on billing determinants, revenues and att allocated cost of service study for the year 1995. The 1995 revenue figures used in the rate design were adjusted to reflect the base rates, Fuel Charge and Conservation Charges applicable to customers' bills in August 1997. Accordingly, the Fuel Charge was set at 50.0490 per kilowatthour. The Conservation Charges in effect l l for each rate schedule at that time are listed in the table below. l Aucust 1997 Conservation Charges R-1, R-2, R-5 $0.00092 per kilowatthour l R-3, R-4, R-6 $0.00092 per kilowatthour G-0, G-1, G-4, G-6 $0.00094 per kilowatthour G-2, G-3, MIT Contract 50.00017 per kilowatthour S-1, G-5 $0.00000 per kilowatthour As with Commonwealth, Cambridge's total revenues produced by reflecting the l above described charges were reduced by 10 percent resulting in the total retail revenue i requirement. The 10 percent redouion was implemented in the unbundled rate design by I reducing the total per bill, per kilowatthour and per kilowatt demand charges including i j the Standard Offer Service Charge, by 10 percent. This process assures that each customer bill under Standard Offer Service reflects 90 percent of the bill otherwise l
i . t-calculated using rates applicable during August 1997. The process used to unbundle Cambridge's rates and revenues was generally the same as that for Commonwealth. However, for Cambridge, some additional steps were l required. In instances in which the total present energy charges are low when compared to the Standard Offer Service and access charges, a portion of the access charge is included with the distribution demand charge. The COSS used methods for l l functionalization and allocation approved by the Department in Cambridge's last rate l proceeding, D.P.U. 92-251. The detailed COSS repon is included as Exhibit I.D. The uniform $/kWh Access Charge applicable in the first year after the Retail Access Date was determined in the same manner as for Commonwealth. This calculation produces a uniform access charge of 2.73 cents /kWh. Exhibit I.B sets forth the rate models used for developing the individual rates. Each of the rate models included in Exhibit I.B pertains to an individual rate schedule and includes the billing determinants and current revenue under existing rates, the functionalized COSS revenue requirements and the proposed unbundled rate prices. Cambridge has provided typical bill comparisons for all rate schedules at Exhibit 1.C. As of March 1,1998, the Cambridge will eliminate its present Large General Interruptible Service Rate and Customer Transition Charge.'" l l l Subsequent to enactment of final legislation, the Companies anticipate filing an exit fee tariff that would be applicable to on-site generators and cogenerators, in accordance with the associated i statutory provisions. l l 4
19 III. TRANSITION COSTS A. Introduction The identification, calculation, accounting and mitigation of transition costs is a critical element of the Plan. The recovery of no more and no less than the full net, non-mitigable level of such costs is of equal importance to the Companies and their customers. The Companies are entitled to recover all costs associated with commitments undertaken to provide electricity to customers in their service territory in accordance with their historical service obligation established by statute and Depanment precedent. The ability of the Companies to continue to provide reliable service in the future depends on the recovery of those unavoidable costs. Correspondingly, customers should pay no more than those transition costs that cannot be avoided after all reasonable mitigation effons have been undertaken to minimize the level of transition eccts. I B. Determination of Transition Costs ! 1 The format for the calculation of transition costs is familiar in that it follows that ' of the approved MECo Settlement (as well as the pending settlements of EECo and l BECo). Exhibits III and IV contain a detailed narrative description of the calculation of transition costs for Cambridge and Commonwealth, with supporting schedules that compute the projected recovery of those costs. The Fixed Component of transition costs includes unrecovered generation plant balances and regulatory assets. These costs are amortized over approximately a 12-year period with canying charges adjusted for tax effects. In determining the carrying charges I applied to unamortized amounts, the Companies have reduced their return on equity by 10 percent. The Fixed Component of the transition costs will be reconciled for 1 1 -
20-accounting apjustments. relating to certain regulatory assets (FAS 106, FAS 87 and FAS 109)" and to apply full credit associated with the divestiture of generating assets. The Variable Component of transition costs includes above-market payments to power suppliers (including economic contract buyouts), certain generation-related i transmission support costs, nuclear decommissioning costs (including nuclear costs independent of operations), above-market fuel transportation costs, payments in lieu of taxes relating to generation (to mitigate the loss of tax revenues to communities affected l by restructuring), mitigation incentive costs and employee severance and retraining costs l relating to restructuring and divestiture. l The recovery of transition costs over time and the resulting level of access charges are dependent on a large number of factors, including the amount of mitigation realized from the divestiture of generation resources. It is possible, especially with Commonwealth, that the access charge in a particular year will not fully cover that year's transition costs, and the recovery will have to be deferred. Deferrals may also accumulate as a result of the difference between the rates for Standard Offer Service and the cost of procuring the power on the open market. Because the markets may be unwilling to provide funds to finance inordinate levels of deferrals, the Plan provides for the imposition of a surcharge if the total deferrals exceed $75 million for Commonwealth and t
" These Financial Accounting Statements penain to the accounting treatment of post-retirement benefits other than pensions (FAS 106), retirement benefits (FAS 87) and income taxes (FAS 3 109).
'2
. The above-market purchased power contracts, the largest portion of the Companies' transition } costs, assume reasonable projections of future market prices for electricity. However, until the j divestiture process is completed (and the contracts are put to a market test), the magnitude of the j this ponion of transition costs remains uncenain. 1 I 2 d
l l
$25 million for Cambridge." The Companies would make a filing with the Department if 1
1 \ such a surcharge became necessary in the future. C. Mitigation of Transition Costs The mitigation of transition costs has been an ongoing aspect of the Companies' j historical obligation to provide reliable service to their customers at the lowest possible l cost. Mitigation efforts include such " routine" activities .ts making short-term l opportunity sales and purchases of power and operating its generating assets in a cost-effective manner. Over the past several years, the Companies have also taken more aggressive actions v,ith regard to purchased power contracts. A report of the Companies' actions, prepared last summer, is included in Attachment 1 [ proprietary)." The report describes the mitigation efforts undertaken by the Companies with regard to each of their generation resources. As indicated in the
~
report, for non-utility generation alone, the Companies have mitigated almost $1.6 billion dollars in costs that would otherwise be paid by customers. However, as part of this Plan, l the Companies will fully mitigate the remaining transition costs through the following j l means. I
- 1. Divestiture of Generation Resources The Companies decided in early 1996 that a divestiture of assets and entitlements was the appropriate course for the Companies to implement in order to become ready for
" The sentement fileo by BECo contains a similar provision. D P.U. 96-23, BECo Settlement, at I.B.5(d).
" The details of the Companies' mitigation efforts recount confidential and proprietary settlement discussions with many of the Companies' suppliers. Accordingly, the Companies request protective treatment of Attachment 1. See Motion for Protective Treatment filed with the Plan.
. i 9
industry restructuring The Companies had been engaged since 1991 in an intensive I l l - mitigation process to reduce the cost of their power supply portfolio, and it became , 1 increasingly clear that a full-scale divestiture would provide the final step of mitigation j i by subjecting the complete portfolio to a market test. Through the design of an ; l \ appropriate auction process, the Companies would be able to derive the highest level of mitigation for the assets and entitlements. This would occur by allowing competitive market bidders to review all the pertinent information relating to the portfolio and to bid a price that they would pay to or receive from the Companies in order to relieve the Companies of their interests in their generation portfolio. In effect, a competitive bidding structure such as an auction allows for bidders with the most optimistic view of the market to purchase the Companies' generation . i resources. Such purchases would result in maximum prices for the resources, thus maximizing the mitigation of transition costs to the Companies' retail customers. The ncure of an auction allows the bidders, who may have unique capabilities (such as an energy trading floor) or other business interests (such as gas pipeline capacity) to bring unique value to a unit or group of units. The timing of the auction is such that bidders will be able to purchase a significant supply at approximately the same time the retail markets are opening up. The Companies' auction is currently under way. Bidders are reviewing the auction solicitations (cne for assets, one for entitlements) and related materials in order to prepare their first round bids which will be due in mid-December. Copies of the auction l
1
, l solicitations ye included in the Plan as Attachments 2 and 3 [ proprietary)." j 1
- 2. Auction Desien and Imolementation l
l The design of the auction began in the first quarter of 1996, when the Companies i established an intemal project team and hired a consultant to work on the initial design j phase. The consultant, ICF Resources, working with the project team, developed the conceptual framework regarding the auction design. The stage one assessment entitled
" Design of Auction Process to Mitigate and Estimate Stranded Costs of COM/Elec's Gen _eration Entitlements" was submitted to the Department in June 1996. The stage two assessment entitled " Implementing an Auction Process for COM/ Electric Generation Assets and Entitlements" was submitted to the Department in March 1997. The Companies, together with ICF Resources, also participated in the Department hearings in docket D.P.U. 96-100.
In the spring of 1997, Goldman, Sachs & Company ("Goldman Sachs") was selected as the Companies' financial advisor and broker for the auction. Between th. months of April and October,1997, Goldman Sachs and the project team worked to . develop a final auction design. An extensive amount of work was required to be - performed by this diverse team to prepare the bid package that would provide the bidders with the maximum amount of information in an understandable and readily available format in order to enhance the bid process.
" The auction solicitations were issued to potential bidders subject to strict confidentiality agreements, because public disciosure would threaten the integrity of the divestiture process and jeopardize the maximum mitigation of transition costs. The Companies therefore request protective treatment of Attachments 2 and 3. Sf.e Motion for Protective Treatment filed with the Plan.
l i
- . - . - - - . .- ~ - - - - - . _ . . . - - -. .- . -
l
, l The auction solicitations and information package were finalized on October 24, 1997, and have been disseminated to the bidders who have qualified to participate in the auction. In order to receive the package, bidders were required to demonstrate their financial viability, to sign a confidentiality agreement that requires them to protect the ,
l confidentiality of the market-sensitive information they receive, and to provide a non-
]
I refundable fee of $5,000. Many bidders have already met the requirements and have l l received the bid packages. l The winning bidder or bidders of the Asset auction will be required to sign an Asset Sale Agreement and other related documents (such as an Interconnection Agreement) with the Companies which provides for the transfer of ownership of the l l electrical generation facilities and property to the new owner for the bid price established in the final round of bidding, plus any closing adjustments. The sale will be subject to the required state and federal approvals for such transfer, and this sale will provide an amount to be used as an adjustment to the access charge related to such assets, as calculated by the Companies and to be submitted for approval to the Depanment. , I' The winning bidder or bidders of the Entitlement auction (for purchased power contracts) will be required to sign an Entitlement Sale Agreement and other related documents (such as an Interconnection Agreement) with the Companies, which provides for the transfer of the entitlements to the winning bidder (s) for the bid price established in the final round of bidding. The entitlement sale will be subject to the required state and federal approvals for such transfer, and this sale will provide an amount to be used as an adjustment to the access charge related to such entitlements, as calculated by the l Companies and to be submitted for approval to the Department. l 1 O-
4 a .- , a .w. +- 25-In thgauction for entitlements, bidders will bid either to pay a certain amount or l to receive a certain amount in exchange for taking over (in a back-to-back transaction) a generation entitlement. To the extent that there is potential for further mitigation of some of the above-market costs associated with existing entitlements, it is expected that bidders will take that into account in formulating their bids. Thus, upon completion of the disposition process, a market-based calculation of transition costs for the entitlements (inclusive of market-perceived mitigation) is obtained. In order to protect their customers from the vagaries and fluctuation of future energy markets, the Companies are requiring bidders for Entitlements to bid a fixed price stream. Annual amounts will not be allowed to fluctuate with indices, thereby minimizing the risk of future market changes to the Companies' distribution customers. The bid will be in the form of a set annual dollar amount (which may vary by year) that the bidder will either receive from the Companies or pay to the Companies in order to receive the rights to the contract entitlement, at the price established in the original agreement between the entitlement seller and the Companies. For an above-market contract, then, it is expected that a bidder will bid an annual dollar amount to be received from the Companies. For those suppliers who will not allow an assignment of their contract from the Companies to the bidder, the Companies will continue to pay such supplier based on the full contract price (including adjustments made pursuant to previous mitigation amendments, if applicable). The bidder will simultaneously pay the Companies an amount representing the full contract price less the amount it has bid. The bid amount paid by the Companies reflects a fully mitigated, market-based measure of the over-market ponion of the power contract. This net amount would therefore be included l
as a transitiop cost and included in the Companies' access charges.
- 3. Sales of Sulfur Dioxide and Nitrogen Oxide Allowances In accordance with the provisions of the Clean Air Act Amendments of 1990, certain of the Companies' generating assets have been allocated sulfur dioxide ("SO2 ")
allowances. These allowances are required to be held and surrendered to cover emissions , of SO2 from the operation of the Companies' generating units commencing in 2000. In order to achieve the maximum value which might be realized for these assets, the SO2 allowances have been included in the sale of the generation assets. Also, under the regulations of the Commonwealth of Massachusetts relating to Nitrogen Oxide ("NO,"), certain generation assets have been allocated NO, allowances for the 1999-2002 time period. In a like fashion, the NO, allowances have also been included with the sale of the generation assets to mitigate transition costs. In addition, to the extent the Companies are able to create additional salable emissions credits, such as Emission Reduction Credits, Emission Offsets, or SO2 allowances, any such credits that are net of those needed for compliance purposes will be offered for sale, with the proceeds applied tow ,rd transition cost mitigation, as well as all proceeds from the annual EPA auction which Cambridge and Commonwealth are entitled to, both under the terms of their respective purchase power contracts with Canal and as owners of the Kendall Station, Cambridge and Cannon Street, New Bedford generation facilities. If a contract is under market, k, a bidder pays the Companies to assume their obligations under the contract, the amount paid to the Companies is credited against the transition costs.
1
. 4. y Sales and Other Transfers of Transmission and Distribution Assets !
In order to reduce further their transition costs, the Companies are increasing their already aggressive program of selling, leasing, or otherwise finding value in various i assets that can be disposed of without affecting service quality or reliability. Four of the { most important elements of this program are: (1) the sale of all real estate located in the Companies' service territory that at any time has been reflected in the Companies' rates ! i and that is no longer necessary for the Companies' operations; (2) the leasing of space on communications towers and transmission structures owned or otherwise controlled by the , l Companies where such space is not needed for distribution company communication and ! I energy transmission, respectively; (3) the full or partial release of transmission rights of way casements on lands over which the Companies hold perpetual and exclusive easement rights and over which transmission facilities have either been retired or ! relocated; and (4) the negotiation, auction or other dispositions of space and rights within the Companies' distribution network to fiber-optic cable companies.
- 5. Reduced Return on Eauity forTransition Cost Recoverv ,
i l Finally, the Plan incorporates a reduced return on equity on transition cost l recovery for Cambridge, Commonwealth and Canal. The 10 percent reduction on equity l return is applied in calculating a return on undepreciated production plant, deferrals and regulatory assets; and on Canal Electric Company's power purchase contracts (including Seabrook). l i
i i IV. UNIVERSAL SERVICE PROGRAMS : l A.. Introduction. ! The Companies' traditional obligation to serve has meant that they have had the ,
. t l responsibility to provide reliable electric service to all customers in their service !
territories at the low',st possible cost. As part of this obligation, the Companies have been required to plan for and provide bundled distribution, transmission and generation services. .' This obligation has included various consumer protections inandated by the Department, as well as the offering oflow-income rates to qualified customers. Under i the Plan, in a restructured environment, it is envisioned that a competitive, unregulated 1 generation market will _be responsible f6r providmg generation service, and electric l l l utilities will offer distribution and transmission services under a regulated regime. L , l The Plan recognizes that, during the transition to a competitive generation market, and to ensure that all customers gain immediate benefits of the restructured industry, the - Companies will be required to offer Standard Offer Service that reflects a 10 percent rate reduction. In the restructured market, the Companies will have a continuing obligation to assist customers to access the competitive power market if a customer does not have a generation supplier. Thus, Default Service is another universal service measure to ensure that no customer will go without electricity. Other aspects of the Plan that support universal service objectives include the Companies' continuing role.in providing low-income discounts, and new Terms and l Conditions that maintain historical consumer protections and include new provisions that j will be needed in the restructured industiy. Each of the universal service components is !- discussed below. 4
,s. --
Lm .,' ] L . l I l B. y Standard Offer Service I The Companies expect that many of their customers may not choose a 1 competitive supplier, at least initially, following March 1,1998 (the " Retail Access 1 Date"). Customers who do not choose a competitive supplier after the Retail Access Date . l l would receive Standard Offer Service during a seven-year transitional period. Such ! I customers may. terminate Stendard Offer Service at any time to purchase from a l 1 competitive supplier in the market. Once they have done so, however, they may not { retum to Standard Offer Service." The Companies' residential and G-1 customers who l take service from a competitive supplier during the first year after the Retail Access Date ! 1 l' may, however, elect to return to Standard Offer Service within 90 days of taking ! alternative service. In addition, any residential customer eligible for low-income rates or ; I Default Service may return to Standard Offer Service at any time and any customer i l i choosing to opt out from an authorized municipal or group aggregation pogram within i 180 days following adoption of the program is eligible to receive Standard Offer Service l t if he was originally enrolled in the Companies' Standard Offer Service. l i i i l'
)
I I l
" A customer taking Standard Offer Service who moves within one of the Companies' service j ,
- territories will be permined to maintain Standard Offer Service.
c I i l ! ti n !
-3 0-The Qtandard Offer Service prices to retail customers (" Customer Rates") are:
Transition Year Price per Kilowatt , hour l 1998 2.8 cents 1999 3.1 cents 2000 3.4 cents 2001 3.8 cents 2002 4.2 cents j 2003 4.7 cents j 2004-5 5.1 cents The Standard Offer Service prices are designed to maintain the economic value of the 10 percent rate reduction throughout the seven-year tenn. The Companies plan to backstop their Standard Offer Service obligation at the pre- , determined prices identified below as part of its divestiture of generation resources. i l However, the Companies are seeking competitive bids from wholesale power suppliers for the right to supply Standard Offer Service and award supply contracts to suppliers at ; prices that are discounted from these Stipulated Prices. On October 6,1997, the Companies issued a Request for Qualifications ("RFQ")'8 to potential suppliers thereby initiating a procurement process through which the Companies intend to award Standard Offer Service Supply Contracts. The Companies are inviting responses from all potential power suppliers including, without limitation, public utilities, municipal light departments, Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978, Exempt Wholesale Generators under the Energy Policy Act of 1992, independent power producers, marketers and brokers. To be eligible to bid, a power supplier must either: (a) be, and, throughout the period that it proposes to I' Sgg Attachment 4
a 31-provide Standard Offer Senice power, continue to be, a member of NEPOOL" or its successor entity and have an own-load dispatch or settlement account established within the NEPOOL billing system; or (b) have an agreement in place, for the full term of Standard Offer Senice availability, with a NEPOOL member whereby the NEPOOL member agrees to include the load to be served by the supplier in its own-load dispatch or settlement account. Further, to be eligible to bid, a power supplier must be able to demonstrate that it has the financial resources to perform under a Standard Offer Senice Supply Contract. Specific pre-bid qualifications, including an audited statement of financial qualifications and other relevant information to ascertain a supplier's ability to perform, are established in the RFQ. After the Companies have reviewed the responses, qualified bidders will be notified and invited to panicipate in the auction. The results of bidding in the subsequent auction process will determine suppliers to be awarded Standard Offer Service Supply Contracts. It is currently expected that the auction will be held as early as December 15,1997. Each bidder in the auction will have the opportunity to bid for the right to supply a portion of the Companies' Standard Offer Service load. Although the Companies cannot predict the number of customers that will continue to rely on Standard Offer Membership in NEPOOL is open to any person or organization engaged in the electric power business (the generation and'or transmission and/or distribution of electricity for consumption by the public, or the purchase, as principal or broker, of Installed Capability, Operable Capability, Energy, Operating Reserve, and'or Automatic Generation Control for resale at wholesale or i retail), whether in the United States of America or Canada or a state or province or a political l subdivision thereof or a duly established agency of any of them, a private corporation, a j pannership, an individual, an electric cooperative or any other person or organization recognized in law as capable of owning propeny and contracting with respect thereto. No person or organization shall be deemed to be eligible for membership if the generation, transmission, or distribution of electricity by such person or organization is primarily conducted to provide electricity for consumption by such person or organization or an affiliated person or organization i
l - t l l Service, or how long they will continue to do so, the aggregate load will initially be j v, 4 l substantial. The Companies intend to encourage customers to choose their own supplier l from the competitive marketplace instead of taking Standard Offer Service. ; 1 l l Based on the auction results, the Companies will establish the Standard Offer l Service suppliers for the entire transition period. For each transition year from March, I l 1998 through February,2004, the auction will determine the suppliers, the share ofload responsibility they agreed to supply and the fixed prices of energy associated with the load responsibility for each year. Successful suppliers in the auction process will be obligated to deliver firm, all-requirements power to the meters of the Companies' retail customers taking Standara Offer Service. Although allocated a percentage ofload responsibility and measured in terms of electric energy to be delivered (kWh) to retail customers, the supplier of Standard Offer Service power will be responsible for all requirements and associated costs for installed capability, operable capability, energy, operating reserves, automatic generation control and VAR support, including tie benefit payments, losses and any congestion charges associated with the supplier's load responsibility and any other requirements imposed by the NEPOOL as it may change from time to time.2 The Companies will make arrangements for Regional Network Service under NEPOOL's open access tariff, Local Network Service under the appropriate distribution company's I or a Related Person. The foregoing capitalized terms can be found in the NEPOOL Agreement. 2 A supplier's load responsibility will be its percentage of the Companies' Standard Offer Service energy requirements (minute by minute, hour by hour, day by day) and associated NEPOOL capacity and ancillary service requirements. I
open access }ariff and Distribution Service under Department jurisdictional retail delivery
- tariffs; The Companies propose to pay suppliers at the following prices, reduced by their applicable bid discounts, for all energy the supplier delivers to Standard Offer Service customers in accordance with its load responsibility and in the respective year. These prices are flat annual values:
Transition Year Price per KHowatt hour ! 1998 3.2 cents 1999 3.5 cents 2000 3.8 cents 2001 3.8 cents 2002 4.2 cents 2003 4.7 cents 2004-5 5.1 cents Also, in the event of substantial increases in the market prices of No. 6 residual l fuel oil (1 percent sulfur) and natural gas after 1999, incremental revenues received by the Companies as a result of the Companies' Customer Rate Fuel Adjustment will be fully allocated among suppliers of Standard Offer Service in proportion to the Standard Offer Service peak demand and associated energy provided by the suppliers to the Companies I in the applicable billing month. The amount of such incremental revenues will depend on the amount by which market fuel prices exceed the predetermined price " trigger" levels. l These triggers have been set, however, to allow a large deadband in which no increases to ; l ! the Companies' Customer Rates are expected. For purposes of the auction and subsequent allocation of supply responsibility, l Standard Offer Service will be denominated on a load responsibility basis. Thus, there l would' be 100 shares on the block for each year of the Transition Period, each i
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o . representing,1 percent cf the hourly Standard Offer Service obligation. With respect to any individual bid, this value is the amount of energy and associated capacity that a winning bidder would be accountable for delivering to the meters of the Companies' Standard Offer Service customers in a given year. The Companies expect that their 1 Standard Offer Service obligations will reduce over time as customers exercise their right of choice and seeme power from competitive suppliers. The Companies will reconcile the revenues billed to retail customers taking Standard Offer Service against payments made to suppliers of Standard Offer Service and recover or refund any under- or overcollections. If revenues are in excess of payments to suppliers, the excess revenues shall be accumulated in an account and credited with interest calculated using the methodology for calculating interest on customer deposits specified in the Companies' Terms and Conditions. The accumulated balance at the end of each calendar year shall be credited to all of the Companies' retail deliver customers ; through a uniform per kilowatthour factor in the following year. If, however, the ! revenues billed do not recover payments to suppliers, or the Companies defer expenses to meet any inflation cap, the Companies shall accumulate the deficiencies in the account, together with interest as calculated above, and recover those amounts by implementing a uniform cents per kilowatthour surcharge on the rates for Standard Offer Service to the extent permitted in accordance with any applicable inflation cap. Under-recoveries, if i any, that remain after the Standard Otter Service transition period ends, shall be 1 recovered from all retail delivery customers by a uniform surcharge not exceeding $0.004 per kilowatthour commencing on January 1,2010. l l n
35-C. p, _ Default Service in recognition the Companies' service obligation, the Companies plan to arrange for generation service as of the Retail Access Date for their customers who have chosen retail electricity from a non-utility affiliated generation company or supplier, but who require electric service because of a failure of such company or the supplier to provide contracted service, or who, for any reason, have stopped receiving such service, and to all customers at the end of the term of the Standard Offer Service. Such generation service is referred I i to herein as " Default Service." Service to individual customers that begin taking Default Service following the Retail Access Date is expected to commence on each customer's normal cycle meter reading date following notification / determination that the customer will be taking Default Service. The Companies' procedures are designed to provide for customers to be switched from one service option to another (eg, from Standard Offer Service to a non-regulated power producer, from one non-regulated power producer to another non-1 regulated power producer, from a non-regulated power producer to Default Service) on their normal cycle meter reading date. However, there may be circumstances (e.e., default of a non-regulated power supplier) that might require a customer to be switched to or from Default Service "off-cycle." In such case, the customer will be switched on a date designated by the Companies. The supplier's obligation to provide service to individual customers taking Default Service shall terminate on the earlier to occur of: (i) the customer's normal cycle meter reading date in the month that the supplier's obligation to supply ends as stated in the Default Service Power Supply Contract; (ii) the customer's meter reading date
i I l l l -3 6- l l t . l following notification / determination that the custonier is terminating Default Sersice; or . l 1 1 (iii) such other date designated by the Companies, which will be no later than the l l customer's normal cycle meter read date in the month that the supplier's obligation to l supply ends as stated in the Default Service Power Supply Contract. Terminations may j i include, but not be limited to: (i) a customer's taking competitive service from a non-l l regulated power producer; (ii) disconnection of service by the Companies in accordance l l
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with regulations and procedures approved by the Department; (iii) closing of a customer's I l account; or (iv) a request or order from the Department. The Companies intend to issue a Request for Qualification ("RFQ") to potential suppliers thereby initiating a procurement process for Default Service Power Supply Contracts. The Companies will invite responses from all potential power suppliers including, without limitation, public utilities, municipal light departments, Qualifying Facilities under the Public Utility Regulatory Policies Act of 1978, Exempt Wholesale Generators under the Energy Policy Act of 1992, independent power producers, marketers and brokers. Eligibility criteria and procedmes will be similar to that described for Standard Offer Service, above. Suppliers will be required to propose a fixed, non-time-of-use, non-rate class l differentiated, energy price with no demand charges which will be billed on a delivered energy basis using consumption as measured at the customer's meter. Pricing may vary by the month in which bills are rendered (.e&, all bills rendered in March are billed at X, all bills rendered in April are billed at Y, etc.). However, the Default Service rate may not exceed the average monthly market price of electricity as defined by NEPOOL, the
. Department, or other such regulatory agency. In addition, all bids must include payment
options withgates that remain uniform for a period of up to six months. The Companies are unable to predict the amount of Default Service that will be required. Customers will be free to leave Default Service to take service from non-regulated power producers. There is also no limit on the number of times that a customer may return to Default Service. The amount of Default Service to be supplied by the winning supplier (s) will be determined in accordance with the Default Service Power Supply Contract. D. Terms and Conditions The Companies have redesigned their Terms and Conditions and rates to provide 1 for retail access while ensuring all customers continue to have non-discriminatory access to electricity. The Companies' programs have been designed to allow customers to select a competitive supplier of their own choosing or continue to receive service through the Companies' Standard Offer Service or Default Service rates. The Companies' Terms and Conditions for Distribution Service (" Terms and Conditions") are based on the Department's June 13,1997 Model Terms and Conditions and incorporate the changes proposed in the Joint Comments on Model Terms and Conditions filed on July 11,1997 (" Joint Comments"). In those Joint Comments, the utility companies proposed specific changes to the Model Terms and Conditions. The Companies have incorporated those proposed changes in their Terms and Conditions for Distribution Service. Consistent with the Joint Comments, the Companies have created both Default l Service and Standard Offer Service Rates and removed the detailed provisions for these i services from the Terms and Conditions. The Joint Comments included language that
would prohibit customers from bypassing distribution senice, thus ensuring all customers will be responsible to pay their fair share of access and other applicable charges. The proposed Terms and Conditions include the Department's current billing and termination regulations that ensure that a customer's rights are protected. The Terms and Conditions continue the Companies' traditional provision of all metering, billing and information services to its customers. A customer will have the option to receive a separate bill for generation service from their competitive supplier. Additional language is included in the Terms and Conditions to facilitate the accurate identification of customers and other critical information that a customer would be obligated to provide when distribution service is provided. The Companies have included a Schedule of Fees and Charges pursuant to the various provisions of the Terms 1 and Conditions. The Companies expect to include additional Fees and Charges as they are developed prior to Retail Access. The Companies' Terms and Conditions include an appendix referring to their Line Extension Policies, which are presently under review. The proposed Terms and Conditions provide the specific provisions that govern the senice provided to the Companies' customers. The Companies will provide service in a non-discriminatory manner to all customers, thus ensuring universal service for all ! I customers. The proposed Schedule of Rates include low-income rates for eligible customers. The eligibility criteria in the Companies' low-income rates incorporate all I applicable regulations of the Department. The Companies' current level of support for low-income customers will continue. In addition, low-income customers will be able to . return to Standard Offer Senice at any time or take Default Senice if, for any reason, they are unable to secure generation senice from a competitive supplier.
39- ! V. PROCEDURES FOR ENSURING DIRECT RETAIL ACCESS TO ALL ELECTRIC GENERATION SUPPLIERS A. Introduction 1 The Companies have examined the procedures that will be necessary to . l ! i l implement so that electric suppliers can compete effectively in the retail electric market l l
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in Massachusetts. These procedures include: establishing rules governing the obligations i l of the Companies and suppliers relating to the delivery of electricity to retail customers; developing a sound methodology for load estimation and reconctP tion for reporting to I l l NEPOOL; setting up systems and protocols for the exchange of data and the processtag i of revenue in support of the enrollment of retail customers by competitive suppliers and , l \ l l of the billing for the retail sale of electricity; developing a comprehensive program to inform suppliers of the information system requirements associated with providing retail j sales in the Companies' franchise sersice areas; and developing procedures to allow for the exchange of customer usage based on metered data. The Companies are also evaluating the use of procedures to reduce the time and resources associated with supplier transactions, such as the uses of electronic bulletin boards, a web site, and the Intemet for commerce. The following sections provide details concerning the Companies' supplier i procedures. The Companies have designed these procedures, utilizing existing systems l ! where appropriate, to provide for an orderly transition to a competitive electric supply market. The Companies' procedures are intended to be consistent with business standards and with industry standards, in order to ensure the fair treatment of suppliers within Massachusetts.
1 i in addition to these Supplier procedures, the Companies have determined that they will waive certain notice, repayment and exclusive purchase provisions in their l tariffs, electric service agreements and DSM Energy Savings Agreements. These actions I by the Companies are designed to provide all retail customers with the opportunity to i choose alternative suppliers and to provide attemative suppliers with the opportunity to l market their generation supplies to all retail customers. l 1 B. Terms and Conditions for Suppliers Included in Exhibits I-A and II-A are sets of the standard " Terms and Conditions For Competitive Suppliers" developed jointly by all of the Massachusetts utility 1 j companies and submitted to the Department in D.P.U. 97-65. These Terms and j l Conditions set fonh the essential obligations and prerequisites of the Distribution i Company 2 and competitive suppliers in the provision of electric service to retail customers. The Massachusetts utility companies developed these Terms and Conditions in a manner that promotes standardization of practices within Massachusetts, while permitting Distribution Companies the ability to use different terms to accommodate company-specific requirements and circurastances. In addition to the detailed provisions of the Terms and Conditions goveming the performance by the Distribution Company and the competitive supplier, certain supporting records requirements and methodologies will be utilizmd to adr. inister the transactions between the parties. For example, for p'rposes of mo.ithly load l ! reconciliation for NEPOOL reporting, the Companies have developed a method of l 2' Capitalized tenns in this section refer t the defined terms included in the Terms and Conditions. j 1 4 4
estimating hourly loads based on detailed statistical analysis of data that underlie class load profiles (ge Section V.C below). The Companies intend to educate suppliers in the capabilities of these methodologies to assist the suppliers in the management of the electricity portfolios. Another example is the adoption of standard formats and transactions for electronic transfer of customer information that were developed by the " Working Group on the Electronic Transfer of Customer Information," which was formed under the auspices of the Department in D.P.U. 97-65 (see Section V.D below). These supporting methodologies and standards will be modified and enhanced as necessary to accommodate the operational requirements of the parties as changes in the retail electric market dictate. Also to be included with these Terms and Conditions will be a schedule of fees for services, activities or specific transactions associated with retail access. The l Companies will file their schedule of fees with supporting cost information after the Department's Order in D.P.U. 97-65. C. Load Estimation and Reconciliation Under NEPOOL rules, all distribution companies are required to report hourly loads by supplier. Hourly loads must be reported twice: first within 36 hours of the close of a day, and second after all meter readings have been completed after the close of a month. In general, the hourly loads reponed each day are to be used by NEPOOL to l allocate savings associated with operation of the pool. The loads reported at the close of ! a month are aggregated to "true up" savings calculated using the daily reported loads. The month-end reported loads are also used to determine each supplier's Capability Responsibility, the amount of capacity that it must stand ready to supply.
If all,. customers were equipped with hourly meters, there would be relatively little effort associated with calculation of these hourly loads: they would simply be aggregated by supplier. However, in the absence of universal hourly metering, each customer's hourly loads must be estimated by a statistically acceptable process. Because some amount of error is inherent in any estimation process, the estimates must then be reconciled such that they sum up to the Companies' hourly total (as determined by SCADA at the bulk meter level). Consequently, load estimation and reconciliation are crucial to the timely implementation of retail access. The source of data to support load estimation is the load research program as administered by the Companies' Pricing and Rate Design Department. In shon, load estimation is to be accomplished by adapting the Companies' short-term hourly forecasting model to an hourly history of rate class data for each class's average customer. The average customer profiles will be adjusted and aggregated by supplier to result in hourly loads for each supplier. Issues that need to be resolved for implementation of the load estimation and reconciliation process include the following: Daily Provision of Supplier Data for Special Ledger / Hand-Billed Customers - Although information pertaining to supplier assignment and l metered usage is available within the billing system for computer-billed customers, separate processes must be constructed for such tasks as daily identification oflarge customers' suppliers, and billed usage. Use of Actual Telemetered Data -- At present, telemetered hourly data ! are available for a small number of customers. However, the Companies' l l
l j l g current hardware, software and procedures for handling these data , preclude the inclusion of actual data in the 36-hour reporting period. ' Suppliers indicate that the uncertainty ofload estimation would be reduced ; if more large customers were to be telemetered. The Companies intend to respond to suppliers who wish to obtain telemetered accuracy and are ; 1 willing to pay for installation of the meter. : Computer Time and Space Required for Daily Estimation - At present, testing of the estimation processes appears to strain computing resources. A number of alternative solutions are being considered, such as
. dedicating storage resources or recompiling the estimation procedures to be more efficient, although they might be slightly less precise.
All tasks are scheduled for completion by March 1,19N. D. Billing /Information System As part of the Companies' efforts to prepare for retail access, several internal teams have been established to identify and implement changes to the computer systems used to provide billing services and access to customer and premise information for use l by employees of the Distribution Company. Additionally, the Companies have been ! i active in collaborative efforts with other Massachusetts utilities, suppliers, and interested i parties in the development of Massachusetts standards for billing and information transfer protocols.
- 1. Internal Activities l The Companies have developed a high-level design for accomplishing the first j phase of Supplier billing by March 1,1998. This high level design will involve ;
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enhancements to the Customer Billing System2 : to bill for Standard Offer Service and Default Service, and to track Suppliers. The Customer Billing System will allow each customer to be associned with either a supplier or the Companies (through Standard Offer Service or Default Service). This will be accomplished through a new online Supplier entry screen and through the existing turn on processes for regular metered, time-of-use metered, and unmetered accounts. Unless otherwise notified prior to the Retail Access Date, all currently existing accounts will be converted so that they are initial.!y associated with the Companies as their Supplier under Standard Offer Service. The Customer Billing System wi!! cjlow a customer to switch Suppliers. This ) I will also be accomplished through a new online supplier entry screen. Pending Supplier l 1 information will be entered with one of three start up options: the new Supplier will be effective as of the next scheduled read date, as of a requested prorated-to read date, or as of a requested actual field read date. When a customer has a Supplier, the Customer Billing System will allow the l l , ability to choose from two billing options. If the customer chooses 'he co r.plete billing l l l l option (one bill), the Companies will calculate and print :he bill for both the Supplier and i themselves. If the customer chooses the pass through billing option (two bills), the Companies will calculate and print the distribution charges and the Supplier will calculate ! and print their ewn bill. The Customer Rilling System's bill calculation, bill print, and online bill inquiry 22 The Customer Billing System refers to the Companies' mainframe billing system. a
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processes wig be modified to accommodate retail choice. The changes will include new charges for Standard Offer Service and Default Service, which will replace the Generation Charge. The Fuel Charge will be eliminated. When a customer has a Supplier and has requested one bill, the Customer Billing System will calculate the distribution charges and segregate the bill. The Customer Billing System's revenue processing will be modified to track Standard Offer Service, Default Service, and Suppliers. I
- 2. Extemal Activities j I
The Companies are currently participating in working groups with other utilities on the electronic transfer of customer information between distribution companies and suppliers. Some of the Extemal Groups that the Companies are active on include:
- The Electronic Business Transactions (EBT) Working Group l l
This EBT Committee put together a Massachusetts standard for the business transactions that will be needed between Competitive Suppliers and Distribution i l Companies. The EBTs were filed with the Department on October 9,1997. The workirig j group continues to consider other related issues (like electronic transmission of custonier historical usage) and any new requirements that come out of the pending legislation md the Department rules and regulations. Some of the standards agreed to within the body of the EBT report include:
- a. Suppliers will do the following tasks electronically, and in the same way, with all of the Distribution Companies in Mmachusetts:
! l l - Notify the Companies that one of the & apanies' distribution customers i )
4 a.-..+.4_.w.m 2.A..am -._aAa a w _L-s. g has enrolled with them to provide generation as of the next scheduled reading date. Notify the Companies whether the customer wants the Companies to bill 1 i Supplier charges on behalf of the supplier or not. Notify the Companies of the Supplier rate that needs to be used if the Companies are going to do the billing for the Supplier. Notify the Companies if they want to drop the customer and no longer provide generation. Notify the Companies of any changes to the enrollment information, k, billing option change or Supplier accesa numi er change.
- b. Distribution Companies will do the following tasks in the same manner, electronically:
Respond back to Suppliers that their enrollment of one of the Companies' distribution customers for generation has been processed successfully. Notify the Suppliers when one of their customers moves within the l Companies' distribution territory and wants to retain them as the Supplier at the new address. Notify the Supplier that their customer no longer takes generation from them, either because the Companies received an enrollment for the customer from a new Supplier or the customer has been " final-billed" with the Companies and no longer has sersice in the Companies' distribution area.
Notify the Supplier of the monthly electrical use as each of their customers Y. l is read and billed by the Companies. l If the Companies bill for the Supplier, notify the Supplier of the monthly Supplier charges. l - When the Companies bill for the Supplier, notify the Supplier as to what payments are made that belong to their accounts. Notify the Supplier what the Companies reported to the ISO for load for l them, k, Load Settlement. i
- Notify the Supplier when a different meter has been set at the customer's address.
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- Notify the Supplier when any changes have been made to the Companies' I l
l account number or billing cycle. Notify the Supplier ifits electronic transactions have failed and why. The Working Group presented consensus positions between Suppliers and Distribution Companies on the following principles:
- All transactions will be effective as of the next scheduled meter reading date with the exception of when a customer moves and retains his Supplier and when a customer wants to drop a Supplier. Those two transactions l can be done using an off-cycle date.
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- A customer can have only one Supplier for any one billing period.
- Suppliers will enroll a customer as soon as they have a legally binding contract and the Distribution Company will accept the first enrollment for that billing period and reject all others.
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-4 8-4, Enrollments must come in two business days prior to the next cycle read date. Enrollments sent in after that cut-off date will be scheduled for the following month's next scheduled read date.
Properly authorized historical information from a customer's account will I be provided to the Supplier by the Distribution Company, although not necessarily electronically at first. Both Suppliers and Distribution Companies will do what is required regarding hardware and software to enable them to use the standardized transactions with Electronic Data Interchange ("EDI") formats. l l e Electronic Data Interchange Testing Subcommittee: l 1 The EDI Testing Subcommittee was formed out of the EBT working group in order to develop guidelines for Suppliers and Distribution Companies to follow when it is time to test the EDI transactions. Each Supplier must test a standard group of EDI transactions with each Distribution Company and this subcommittee is developing a standardized test plan and set of test cases that each company can use in their individual ; , company testing. l
- EDI Transactions Subcommittee The EDI Transactions Control Subcommittee was formed to coordinate the mapping of the Massachusetts data formats to the EDI standard formats and to report on the National standards for utility electronic transactions.
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- EBT Document Change Control Subcommittee:
The EBT Document Change Subcommittee was formed to monitor changes that
need to be gnade to the EBT document and to coordinate getting revisions to the Department and out on a central website for all other working group members to review. 1 E. Supplier Education A requirement for retail access is the ability of Suppliers to operate and conduct , l retail transactions efficiently. As with other changes, the Companies have participated to develop uniform Supplier Education and training workshops. Additionally, the i Companies are evaluating additional educational and training methods that can be l implemented in addition to the state-wide efforts.
- 1. External Activities The Supplier Training Subcommittee, which was established as a subset of the !
Electronic Business Transactions Working Group, has been charged with developing ; l state-wide training programs for Suppliers. These training sessions will be administered I by the major utilities within the state including the Companies. Some of the items that will be included on the agenda for the workshop will include: Regulatory Updates. l Choice Implementation Essentials, a review of Department-approved Terms and Conditions, and an oversiew of the Electronic Business Transaction Standards. It is also expected that these workshops will offer an opportunity to provide technical sessions on l , some of the more sophisticated issues such as Load Estimation, Billing System i 1 requirements, Telemetering Alternatives, or other topics of specific technical interest. In addition to the Supplier Workshop, the collaborative has been developing a Supplier Guide to be made available to all Suppliers. It is expected that the Suppliers Guide will aid in providing essential information to competitive Suppliers by 1,roviding a summary of the key processes and communication protocols that must be understood and
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.' l implemented, by Suppliers and Distribution Companies. Some of the topics that will be covered and items that are being considered for inclusion in the Supplier Guide will be l Retail Access Implementation Requirements, including a copy of the Terms and i l l Conditions - Competitive Suppliers, and a copy of the Electronic Business Transaction l
Standards. Included as part of the Supplier Guide will be Supplier Registration information, Telemetering options, Billing requirements and options, and Information Exchange information, Load Estimation information and Common Information such as distribution company contacts.
- 2. Internal Activities l In addition to the collaborative efforts mentioned, the Companies have considered additional measures to educate Suppliers and to allow them to operate efficiently within l the Companies' service territories. The Companies are in the process of scheduling l l .
l Supplier focus group meetings to solicit feedback from Suppliers on additional effenngs ! that the Companies can implement to allow for a smooth transition to a restructured electric industry. Other efforts under discussion include expanding the Companies' participation in the Edison Electric Institute - National Account Program to assist Suppliers who work with national and chain accounts. Additionally, consideration is being given to l expanding the Companies' web site to allow Suppliers to obtain pertinent information. Many of these programs will be available prior to the Retail Access date; however, the l programs will continue to change following the Retail Access Date in an effort to provide programs to Suppliers that are responsive to their needs. I I
F. e Metering The Companies, through their participation in the development of Model Terms and Conditions, participation in the collaborative to develop Load Estimation and ; Reconciliation, as well as participation within the Metering, Billing and Information Systems collaborative, have supported the position that a transition to customer choice does not require the installation of sophisticated metering equipment. This premise is based en the belief that through load estimation and reconciliation, retail access can occur, be billed and be reconciled using existing tariffs and the existing metering and billing systems. The Companies have begun development and implementation of procedures and l standards to allow the Companies to respond to requests by Suppliers and customers to provide more sophisticated metering and metering output capabilities. Additionally, the Companies are participating in collaboration with other interested parties to develop consistent baseline service offerings between utilities and Suppliers within Massachusetts. Some of the service offerings being considered include the following: Suppliers that opt for actual hourly data but do not wish to purchase their own equipment may develop a service agreement with the Distribution Company. At an agreed-upon price, the Distribution Company will l 1 acquire and install the appropriate hourly recording equipment. As a result of this option, the Distribution Company would provide actual hourly ; loads to NEPOOL in lieu ofload estimation. The Customer / Supplier shall j contract with the Distribution Company for, or separately arrange for, the 1 I
installation and ongoing charges associated with the phone line required under this option. For Suppliers that op for actual hourly data and wish to own their own equipment the Distribution Company would provide energy pulses to a Supplier-owned recorder. Where the Supplier opts for actual hourly load reporting by the Distribution Company in lieu of estimation, the Supplier must purchase an hourly recorder from a list of Distribution Company approved equipment, and provide a communications line to the recorder accessible by the Distribution Company. The Distribution Company would thus obtain and report actual hourly reads to NEPOOL. Should the ability to access the hourly data be impaired, the Distribution Company would revert to load estimation until such time access is restored. The Supplier may remove both the recorder and the communications line upon termination of the Supplier / Customer contract. Suppliers that choose Distribution Company load estimation (basic service) but wish to own their own equipment for bill calculation or other services may purchase any device that accepts the Distribution Company pulse outputs, Lea , these devices do not have to be on the Distributior-Company approved list. The Companies will work with Customers, Manufacturers and Suppliers and other utilities to develop and standardize on other, more advanced communication interfaces as they evolve. Upon request, the Companies will consider a Supplier's or Customer's
i .- ,' l - request for ,the. installation of a particular meter or communications device. The Companies will evaluate whether the meter or communication device meets all applicable standards and requirements; and in the case of a device installed on a meter owned by the Companies, does not interfere with the operation of that meter. Any communications device or meter approved for installation by the Companies shall be owned, controlled and maintained by the Companies. The Supplier or Customer shall bear all costs associated with the installation, ownership and maintenance of the communications device or meter. The Companies believe that by providing core baseline service offerings to all Suppliers, and by establishing procedures to evaluate special metering requests, Supplier: will be able to develop and offer a variety of products to their customers. Additionally, by establishing consistent metering policies, smaller Suppliers will not be placed at a disadvantage during the initial stages of retail access to larger Suppliers who may have established metering capabilities and a billing system infrastructure in place. l G. Waivers Pertaining to Prior Commitments With Retail Customers In order to extend the benefits of competition to all retail customers, and to allow for effective competition for suppliers in all customer groups, the Companies will treat prior commitments under their rates and contracts as follows:
- 1. Economic Develcoment Rates The following economic development rates in effect for Commonwealth have certain notice and repayment provisions regarding a customer's purchase of electricity l
from an alternative supplier: Large General Economic Development Rate G-3 (ED) l (Closed) - M.D.P.U. No. 286; Large General Economic Development Rider Rate G-3 i
r 4 54-l (ED)- M.D.pU. No. 304; Service Extension Discount Rider Rate G-3 (SXD) - M.D.P.U. No. 297; and Vacant Space Rider Rate G M.D.P.U. No. 278. Effective on the Retail Access Date, Commonwealth will waive the notice provisions in these tariffs. Further, Commonwealth shall require no repayment by the customer as would otherwise be l l required under the terms of the tariffs. These notice and repayment waivers also will apply to any of Commonwealth's economic development contracts approved by the l Department. Nothing in this Plan will require the Companies to waive the advance notice requirement required before the retail customer may install on-site generation for its own i i use or to bypass the Companies' distributions systems.
- 2. DSM Energy Savings Agreements Many of the Companies' commercial and industrial customers have participated i
in the Companies' demand-side management programs that provide for termination of I their participation if the customer purchases electricity from an attemative supplier. The Companies will waive this termination provi' ion insofar as it would limit the customer's ability to purchase electricity from an alternative supplier. Mothing in this Plan will j require the Companies to waive this provbion before the retail customer may install on- ! I site generation for its own use or to byr ass the Companies' distributions systems. l ! I I i i . 4 i 8
i l l VI. ENERGY EFFICIENCY AND RENEWABLE-RESOURCE PROGRA IS The Companies are committed to continuing support of energy efficiency and renewable resource programs. This tangible commitment, consistent with the l Department's restmeturing principles, the settlements filed by other electric companies and the pending statutory mandates, will include funding at the following levels: Enernv Efficiency Procrams2 ' Renewable Resource Procrams 1998: $0.00330 per kWh 1998: .$0.00075 per kWh 1999: $0.00310 per kWh 1999: $0.00100 per kWh 2000: $0.00285 per kWh 2000: $0.00125 per kWh 2001: $0.00270 per kWh 2001: $0.00100 per kWh 2002: $0.00250 per kWh 2002: $0.00075 per kWh It is anticipated that the revenues generated for the renewable resource programs will be remitted to the Massachusetts Technology Park Corporation that will be mandated to administer a trust fund to promote renewable energy in the Commonwealth. The Companies intend to build on existing programs and develop effective and meaningful new approaches to promote energy efficiency efforts. The Companies are in an active collaborative process with a number of interested stakeholders to develop detailed programs consistent with the overall commitment to fund energy efficiency over a five-year period at the above revenue limits. The Companies will collect the revenue necessary to implement these programs through a mandatory per kilowatthour charge. This charge shall be implemented in a manner consistent with any legislative mandate relating thereto. i i 2' The level of annual per kWh collection for energy efliciency programs will be adjusted to comply with all applicable legislative mandates. i l
j A. ,, Summary of Current Programs and Budgets The Companies began implementation of their GreenSaver Integrated Resource Management Program ("GreenSaver IRM Program") on July 1,1994. Through the GreenSaver Program, approved in Cambridae Electric Linht Comoanv/ Commonwealth Electric Comoany, D.P.U.' 91-234, the Companies put out to bid the opportunity for qualified energy sersice contractors and customers to provide the Companies with measured and/or measurable ' energy savings. The Greensaver IRM Program is currently slated to close as of June 30,1998, although an extension is being negotiated with at least one contractor. In addition, the Companies currently implement the following demand-side 1 management ("DSM") programs: (1) Residential Lighting; (2) Residential Low-Income Appliance Management (coordinated with the South Middlesex Opportunity Council and l local weatherization assistance program agencies); (3) Conservation Voltage Regulation, and (4) an Emergency Conservation Plan for periods when there may be a shortage of i generation capacity available. The Companies will likely continue these existing efforts 1 over the five-year period. Also, the Companies continue to generate savings from so-called pre-approval programs such as the Customized Rebate Program and the Residential Electric Space Heating Program that preceded the GreenSaver IRM. Further, in accordance with the D.P.U. 95-95 settlements, the Companies have undertaken i i emerging technologies / market transformation efforts including: (1) Geothermal /High l Efficiency Heat Pump; (2) E-SEAL (residential new construction); (3) Residential i Education; (4) C&I Education; and (5) Residential Rooftop Photovoltaic. Sss Cambridge ! Electric Linht Comoanv/ Commonwealth Electric Comoany, D.P.U. 95-95, at 4-5 (1996). i
57-The Companies will work with interested stakeholders, as noted below, to determine which of these D.P.U. 95-95 settlement efforts should continue durir.g the five-year period. , B. Collaboration with Stakeholders Consistent with the overall five-year commitment noted above, the Companies will work with stakeholders in the final development and subsequent implementation of the details of the five-year plan. Already, representatives of the following organizations I have attended an October 22,1997 introductory meeting:
- Consortium for Energy Efficiency e Northeast Energy Efficiency Pannership e IRATE e Conservation Law Foundation e Northeast Energy Efficiency Council e Massachusetts Attomey General's Office e Massachusetts Department of Public Utilities
- South Middlesex Opponunity Council e Energy Consonium In addition, representatives from the Massachusetts Division of Energy Resources requested and received copies of the presentation materials.
The general time line for the Collaborative process will be driven by legislative mandates. Specifically, the Companies will wcrk cooperatively with panies within the time frames established by legislative mandates but would plan to submit funher details with respect to the five-year plan described herein by March 1,1998. From the Companies' perspective an inclusive, collaborative process, resembling that of the ! Cambridce Electric Light Comoanv/ Commonwealth Electric Company. D.P.U. 95-95 l i settlement discussions, will be the goal.
* , 1 C. Programs and Budgets The Companies, on or about March 1,1998, working with the Collaborative group, will develop and file details of the five-year plan by defining target budgets for each market sector, and assigning specific " committed" budgets to those activities that .
1 can be estimated with a high degree of certainty, such as ongoing payments arising from the GreenSaver IRM Program. In addition, within each market sector, the Companies will describe the incremental programs and activities that will be undertaken and define annual spending targets and impacts based upon available funds collected through the energy efficiency charge. In the residential sector, the Companies will fund and implement ,all low-income energy efficiency efforts mandated by any applicable legislation. j Consistent with Department precedent allowing flexibility in allocation of budgets within general market sectors, the Companies will request the ability to exercise i discretion in shifting funds among programs as the market and in-field experience dictates. See, g&, Fall River Gas Comoany. D.P.U. 96-62 (1997). The Companies will also describe the competitive procurement processes and the types of monitoring and . l evaluation activities they will pursue, and how (jA, independently or via collaboratives 1 such as NEEP) such activities will be pursued. Finally, proposed incentives associated ! with market-oriented and market transformation programs will be provided, based on objective, performance-based standards. The following is a brief summary of some of the options that will be considered by the Collaborative in fimalizing the details of the five-year energy efficiency programs and budgets.
I
. In thg residential heating sector, approximately $725,000 over the five-year period is committed to GreenSaver IRM Program and other fixed conservation expenses. The following programs will be evaluated for funding from remaining available revenues:
- Customer Education Programs
- Geothermal /High Efficiency Heat Pump Program e Residential New Construction (E-SEAL) Program
. Low Income Programs / Appliance Management (as per statute)
- Residential Lighting Program o Residential Luminaires (NEEP)
- Horizontal Axis Washer Program (NEEP)
- DOE / EPA ENERGY STAR Initiatives In the residential non-heating sector, approximately $850,000 is anticipated for GreenSaver IRM Program and other fixed conservation expenses over the five-year period. The following programs will be evaluated for funding from remaining available revenues:
- Residential Lighting Program
. Horizontal Axis Washer Program (NEEP) e Residential Luminaires (NEEP) e DOE / EPA ENERGY STAR Initiatives e Low Income Programs / Appliance Management (as per statute)
- Apartment-Sized Refrigerator Program (CEE)
In addition, the Companies will target a new program to the single family attached (k, condominium) housing market, both in the residential and commercial (multifamily) sectors. In the small general sector, because the GreenSaver Program has seen much of the available lighting retrofit work completed, the Companies will replace the existing GreenSaver IRM Program with several new initiatives and programs targeting non-lighting measures. Approximately $4.8 million will be required for GreenSaver and other A
committed payments in this sector over the five-year period. New programs will be e directed toward the following efforts:
- Premium Efficiency Motors (NEEP) i e Unitary HVAC (NEEP) e HVAC Controls
- High Efficiency Replacement Equipment
- Public Housing Authority Program
. Market Transformatiort/ Education (Including New Construction)
Approximately $6 million is budgeted for GreenSaver and other committed l payments in the medium and large general sector over the five-year period. The following programs will be evaluated for funding from remaining available revenues:
- Premium Efficiency Motors (NEEP)
I e Unitary HVAC (NEEP) l e HVAC Controls l e High Efficiency Replacement Equipment
- Public Housing Authority Program e Market Transfonnation/ Education (Including New Construction)
- Electro-Technology Applications and Process Systems in these medium and large C&l market sectors, the Companies will offer program designs that address the program efficiency issues now being considered in the industries'
" Accelerated Application Process."
l In conclusion, the Companies are committing to fund energy efficiency efforts in all market sectors over the next five years, at levels consistent with recent legislative initiatives. The revenues to support this effort will be collected from a mandatory per kilowatthour charge applicable to all customers. Details regarding the annual budgets and specific programs to be offered over this five-year period, including comprehensive low-income and market transformation programs, will be filed by the Companies on or L before March 1,1998. In developing this detail, the Companies will continue their existing collaborative efforts with a broad-based group of stakeholders. \
, l VII. IMPACT ON EMPLOYEES AND COMMUNITIES A. Introduction The Companies have been working diligently to facilitate a smooth transition to a I I
restructured electric industry. In this process, the Companies have sought to ensure a full understanding of the changes in the marketplace by their employees and the many cities l and towns served by COM/ Electric. As discussed below, the Companies believe that, as a result of these efforts and through continued outreach programs to employees and the communities served by the Companies, an efficient transition will be achieved. B. Employee Programs l I
- 1. Educational Efforts ;
Discussion of the restructuring of the electric utility industry has been i incorporated as an integral part of the Companies' communications program since 1994. i These discussions have been designed to create, in pan, an educated and knowledgeable workforce that will be crucial in carrying out further public education campaigns. In . 1 addition, these discussions prepare the workforce for the significant changes that are forthcoming in the electric industry as it relates to their own jobs. Specific employee communication efforts have included: (a) regular discussions between the President and other senior managers and employees at all levels of the organization; (b) a series of briefings on restructuring issues for those employees that have interactions with customers and community leaders; (c) articles and updates in the monthly employee newsletter; (d) recurring depanmental meetings; and (e) individually l addressed letters from the CEO and President on relevant issues. l i l
, Follo, wing enactment of legislation, the Companies expect to continue these educational programs for employees in eamest. These efforts will include: (a) development of written materials and a series of presentations to employees; (b) development of detailed training programs for customer service, district and marketing representatives as well as a speakers' bureau and telephone information hot line; and (c) the use of group meetings, the employee newsletter, e-mail and an employee web site to provide: funher details on restructuring issues. The Companies view the successful implementation of these education programs as being critical to the overall restructuring process.
- 2. Other Emplovee Imoacts In anticipation of the restructuring of the electric industry and as part of an exhaustive effon to reduce costs, the Companies have undergone a significant streamlining of their operations and a consolidation of certain functional areas. In particular, the number of employees has been reduced by approximately 40 percent through a 1993 job reduction program, attrition and a personnel reduction program in 1997. Moreover, tight control of pay and benefit increases has been exercised for managerial, administrative and union employees.
As the divestiture process is completed, the impact on jobs has received close attention. Power generation and power contract-related personnel covered by relevant collective bargaining agreements will be hired by the new plant owners. In addition, non-union employees may also be hired by such owners. In any event, employees displaced through the divestiture process will be eligible for severance benefits. The costs of any such severance, outplacement, retraining or other related employee transition costs
i..
. associated dh industry restructuring will be recovered through the Companies' access charge. i The Companies have also implemented a consolidation of various functions to
]
1 improve the efficiency of operations. In some cases, this has involved a shifting of work locations for non-union personnel among the Companies' offices in Wareham, Southboro t I and Cambridge. l ! Aside' from power-generation functions, the Companies expect upon restructuring ! l l that they will continue to operate as transmission and distribution. companies and provide safe and reliable service on behalf of their customers. Accordingly, no significant additional actions to reduce personnel further are anticipated at this time. l l C. Community Issues . l
- 1. Customer Education l
The Companies have had an active program to educate customers about the electric industry restructuring process since 1995. The strategy for this outreach has been l to: (a) start a process and build awareness about the relevant issues; and (b) correct any misinformation that was present. Specific efforts have included bill inserts, the l l production of a 28-minute video, customer seminars, published articles in customer newsletters, press releases and media interviews. In addition, periodic meetings with community leaders have been conducted to provide additional information. Similar educational programs will be implemented following the enactment of restructuring legislation. A speakers' bureau will be developed for meetings with media, j i
- community, industry, civic, senior citizen and low-income groups. Materials will be l disseminated for distribution with formal presentations and trade shows, as well as j i
i
- .. - - -. . . i
, ,o
# l
, 64-distribution for city and town halls, libraries and senior centers. In addition, other mechanisms such as videos, bill insens, radio and newspaper advertisements, information booths, a toll-free hot line and a web site will be implemented as part of the continuing communications outreach. The Companies will also continue their active pn. ipation in j other community programs and economic development activities. The Companies believe that all of these approaches will ensure that all customer groups have available the necessary information to ensure an efficient movement to customer choice.
i Moreover, the Companies expect that several communities, especially on Cape Cod, may develop plans to aggregate loads to buy electricity in bulk. These aggregated groups may present important opportunities for customers, particularly residential and small business customers, to save on their electricity costs. The Companies will I cooperate fully with groups in their aggregation efforts and inform customers of such l aggregation options.
- 2. Pm.perty Tax Issues i i
The Companies pay personal property and real estate taxes to each community in the service territory. These taxes are based on the number and assessment on offices, power production facilities, poles, substations, and the like. With the exception of taxes paid to communities hosting power production facilities (Cambridge, Sandwich, Oak l l Bluffs and Tisbury), changes brought about by restructuring are not anticipated to change l the amount of taxes paid to local communities. I j i i i
- 3. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
- a. The Compact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 1
- b. The Companies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 1 4 Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 l
l . B. Motion for Protective Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
- 1. I ntrod uction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
- 2. Standard of Review ................................ 10 1
- 3 Positions of the Companies . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 I 4. Analysis and Findings . . . . . . ......................'. 10 V. STANDARD OF REVIEW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 VI. ISSUES.................................................. 15 A. S tan dard O ffe r . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
- 1. Standard Offer and Competitive Pricing . . . . . . . . . . . . . . . . . . . 15 ,
- a. The Act ................................... 15
- b. The Plaa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 l c. Positions of W.e Parties . . . . . . . . . . . . . . . . . . . . . . . . . 16 l l i. Enron, The Compact, and SORE . . . . . . . . . . . . . 16 i ii. Attorney General . . . . . . . . . . . . . . . . . . . . . . . . 17 iii. Companies ............................ 17
- d. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 19
- 2. Standard Offer and Backstop Service ..................,. 23 l a. I ntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23 l
- b. The Plan . . . . . . . . . . . . . . . . . . . . . . . . . . ........ 23
- c. Positions of the Parties . . . . . . . . . . , . . . . . . . . . . . . . . 24
- i. Compact and Enron . . . . . . . . . . . . . . . . . . . . . . 24 ii. The Companies . . . . . . . . . . . . . . . . . . . . . . . . . 25
- d. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 23
(
. s '.
i l l B. Retail Ddivery Antes and Rate Reductions . . . . . . . . . . . . . . . . . . . . . . 29 1. l introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 '
- a. The Act ................................... 29 i
- b. The Plan . ........................... ..... 29
- 2. Ten Percent Rate Reduction . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
- a. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 I l b. Commonwealth's Baseline Fuel Charge . . . . . . . . . . . . . . 32
- i. Positions of the Parties . . . . . . . . . . . . . . . . . . . . 32 i (A) The Attorney General . . . . . . . . . . . . . . . . 32 i (B) The Compaules . . . . . . . . . . . . . . . . . . . . 33 l ii. Analysis and Findings . . . . . . . . ............ 33 ;
- c. The Companies' Use of Deferrals . . . . . . . . . . . . . . . . . . 35 l
- i. The Companies' Proposal . . . . . . . . . . . . . . . . . . 35 )
ii. Positions of the Panies . . . . . . . . . . . . . . . . . . . . 36 i iii. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . 37 l l 3. Unbundled Distribution Rates . . . . . . . . . . . . . . . . . . . . . . . . . . 38 l a. The Pl an . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 ;
- b. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . . . 38 l
- c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 39
- 4. Bundled Charges . . . . . . . . . . . . . . . . . . . . . . ........... 40
- 5. Negative Charges On Tariffs . . . . . . . . . . . . . . . . . . . . . . . . . . 41 l
- 6. Streetlight Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 42
- a. Th e Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . , ..... 4:
(- b. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . .~. 42
- i. The Compact . . . . . . . . . . . . . . . . . . . . . . . . .. 42 ii. The Companies . . . . . . . . . . . . . ........... 43
- c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 43
- 7. Tariff Provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . 44
- 8. Notification Period for Self. Generation . . . . . . . . . ......... 46
- a. I ntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
- b. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . . . 46
- i. The Compact . . .. . . . . . . . . . . . . . . . . . . . . . . . 46 ii. The Companies . . . . . . . . . . . . . . . . . . . . . . . . . 46
- c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 47
- 9. Commonwealth's Notification Period for Termination of G.2 and 0 3 S e rvi c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
- a. Introduction . . . ............................. 47
- b. Positions of the ferties . . . . . . . . . . . . . . . . . . . . . . . . . 48
- c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 48 4
- C. Speci al Rat es . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
- I Low. Income Tariffs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
- 2. Termination of Discoura TraitTs . . ..................... 50
- a. Introduction . ... .......................... 50
- b. Positions of the Panies . . . . . . . . . . . . . . . . . . . . . . . . . 51
( , i. Acushnet Rt% Company, Inc. . . . . . . . . . . . . . . 51 f
o < . s, ., t e ii. S O RE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51 iii. The Companies . . . . . . . . . . . . . . . . . . . . . . . . . 52
- c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 52
- 3. Interruptible T,utes . . . . . . . . . . . . . . . . . . . . . . . . . . ...... 53 D. Transition Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
- 1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
- 2. Categories and Amounts of Transition Costs . . . . . . . . . . . ... . . . 55
- a. Overview of the Plan . . . . . . . . . . . . . . . . . . . . . . . . . . 55
- b. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . . . 57
- i. The Attorney General . . . . . . . . . . . . . . . . . . . . . 57 ii. The Companies . . . . . . . . . . . . . . . . . . . . . . . . . 59
- c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 61
- 3. Mitigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62
- a. Overview of the Plan . . . . . . . . . . . . . . . . . . . . . . . . . . 62
- b. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 63
- 4. Depreciation Rate for Fixed Generation Anets . . . . . . . . . . . . . . 65
- a. The Companies' Proposal . . . . . . . . . . . . . . . . . . . . . . . 65
- b. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 66
- 5. Mitigation Incentive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
- a. The Companies' Proposal . . . . . . . . . . . . . . . . . . . . . . . 66
- b. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . . . 67 f c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 68 1 6. Return on Equity for Transition Charge Calculation . . . . . . . . . . . 70
- a. The Act ..................... ............. 70
- b. Th e Pl an . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71
- c. Positions of the Parties . . . . . . . ................. 71 (i) Attorney General . . . . . . . . . . . . . . . . . . . . . . . . 71 (ii) Companies ............................ 72
- d. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 72
- 7. Reconciliation Account: Rate of Return and Base Transition Charge A dj ustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73
- a. The Pl an . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73
- b. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . . . 74
- c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 75
- 8. Capital Structure to Use for the Transition Charge . . . . . . . . . . . . 77
- a. The Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
. b. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . . . 78
- i. Attorney G:neral . . . . . . . . . . . . . . . . . . . . . . . . 78 ii. Companies . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78
- c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 78
- 9. Calculation of Cost of Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . 79
- a. The P l an . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79
- b. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . . . 79
- i. Attorney General . . . . . . . . . . . . . . . . . . . . . . . .
( ii. Companies . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 80
l
. 7 +1 e
- c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 80
(~ 10. Recognizing Changes in Capital Structure . . . . . . . . . . . . . . . . .
- a. The Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
81 81
- b. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . . . 81
- i. Attorney General . . . . . . . . . . . . . . . . . . . . . . . . 81 ii. Companies ............................ 81
- c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 82 ,
E. Quality of Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 ,
- 1. The Act ........................................ 82
- 2. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
- 3. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 I F. Other l ssues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
- 1. Demand-Side Management ("DSM") . . . . . . . . . . . . . . . . . . . . . 83 ;
- a. The Act ................................... 83 l I
- b. The Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 j
- c. Positions of the Parties . . . . . . . . . . . . . . . . . . . . . . . . . 85 j
- i. The Compact . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 i ii. CISR................................ 85 '
iii. Attorney General . . . . . . . . . . . . . . . . . . . . . . . . 86 { iv. The Companies . . . . . . . . . . . . . . . . . . . . . . . . . 87 !
- d. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . 88
( '
- 2. Renewable Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ,. . 88
- a. The Act ................................... 88
- b. The P l an . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
- c. Analysis and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . 89 l VII. CON C LU SI ON . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89 VIII. ORDER.................................................. 91 I
i IX. DI S S ENT IN PART . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 . l 1 3 i
.. ? ', .* r I. INTRODUCTION l On November 19,1997, Cambridge Electric Light Company (" Cambridge"),
l Commonwealth Electric Company (" Commonwealth") and Canal Electric Company l (" Canal") (collectively, the " Companies") filed with the Department of Public Utilities, now l renamed the Department of Telecommunications and Energy (" Department"), a plan to review their electric restructuring proposal (" Plan"). The Department docketed this matter as D.P.U./D.T.E. 97-111. This Order presents the background, procedural history, a description of the Electric Industry Restructuring Act, Chapter 164 of the Acts of 1997 (the "Act"),8 a general ; i l overview of the Plan, the applicable standard of review, an issue by issue summary of the Plan, and our analysis and findings. The analysis and findings address whether the Plan is l l . consistent, substantially complies, or complies fully with the applicable provisions of the Act. i ( While approving the implementation of the Plan, this Order directs Cambridge and i Commonwealth to make an additional filing i comply with the Department's directives l- ! contained herein. II. BACKGROUND On March 15,1996, the Department opened a generic rulemaking to guide the development and evaluation ofindividual electric company restructuring plans. Electric Industry Restructurine, D.P.U. 96-100 (1996) ("D.P.U. 96-100"). On May 1,1996, the Department issued proposed rules. D.P.U. 96-100, Exolanatory Statement and Pronosed l- ' On November 25,1997, Chapter 164 of the Acts of 1997, entitled "An Act Relative to i Restructuring the Electric Utility Industry in the Commonwealth, Regulating the j i ( Provision of Electricity and Other Services, and Promoting Enhanced Consumer Protection Therein," was signed by the C . v .Vwy - vm -
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Eulss, May 1,1996. On December 30,1996, the Department, in the same docket, issued its plan for a restructured electric industry, including Model Rules and a Legislative Proposal. D.P.U. 96-100, Electric Restructurine Plan Model Rules and Lenislative Prooosal, December 30,1996. On January 16,1998, the Department proposed draft rules implementing the Act for public comment. D.P.UJD.T.E. 96-100, Order Pronomina Renulations and Solicitino Comment, January 16,1998. On February 20,1998, the Department issued fmal rules implementing the Act. D.P.UJD.T.E. 96-100, Electric Industry Restructurine Rules. February 20,1998. 2) III. PROCEDURAL HISTORY Pursuant to notice duly issued, the Department received initial comments on the Companies' Plan from three entities: the Companies, Enron Capital and Trade Resources 2 In addition, the Department approved a settlement of the Massachusetts Electric Company Restructuring Plan, D.P.U. 96-25, on February 26,1997, and an r.mendment ofits restructuring plan on July 14,1997, D.P.U. 96-25-A. On December 23,1997, the Department issued an Order finding that the Settlement previously approved by the Department substantially complies or is consistent with the Act. D.P.U/D.T.E. 96 B, and issued an Order on its compliance filing on January 20,1998. The Department approved a settlement of the restructuring plan of Eastem Edison Company, D.P.U/D.T.E. 96-24, on December 23,1997. That Order is the subject of several motions for reconsideration, now pending. On January 20,1998, the Department issued an Order on Eastern Edison Company's compliance filing. The Department also approved a settlement of the restructuring plan of Boston Edison' Company, D.P.U/D.T.E. 96-23, on January 28,1998. That Order is on appeal, before the Supreme Judicial Court of the Commonwealth. On February 20,1998, the Department issued an Initial Order approving, subject to review and reconciliation, the restructuring plan of Western Massachusetts Electric Company, D.T.E. 97120. On February 26,1998, the Department issued an Intial Order, subject to review and reconciliation, the restructuring plan of Fitchburg Gas and Electric Light Company, D.T.E. 97-115. I-u
.. *; , s'; O D.P.U/D.T.E. 97-111 Page 3 ("Enron"), and Harvard University. The Department conducted five public hearings in the Companies' service territories on December 22,1997, January 5,1998, January 8,1998, January 27,1998, and January 29,1998 in Cambridge, Marstons Mills, New Bedford, Plymouth, and Cambridge, respectively. The Department convened a procedural conference on January 6,1998, and issued a procedural schedule on January 16,1998. D.P.UJD.T.E. 97-111, Interlocutory Order on Procedural Schedule (1998) (" Interlocutory Order"). Pursuant to G.L. c.12, f 11E, the Attomey General of the Commonwealth (" Attorney General") filed a notice of intervention in the proceeding. In addition, the Department granted the petitions for leave to intervene filed by the following entities: Division of Energy Resources (" DOER"); Associated Industries of Massachusetts; Towns of Barnstable 11 sh, Barnstable County, and the Cape Light Compact (the " Compact"); Boston Edison Company; Cape and Islands Self-Reliance Corporation ("CISR"); Conservation Law Foundation ("CLF"); Energy Pacific; Enron; Action, Inc., Massachusetts Energy Directors Association, Massachusetts Senior Action Council, and Cape Organization for the Rights of the Disabled (collectively, Low Income Intervenors ("LII")); Massachusetts Institute of Technology ("MIT"); Northeast Energy Associates ("NEA"); Northeast Energy Efficiency Council ("NEEC"); Save Our Region's Economy (" SORE"); and Westem Massachusetts Electric Company. The Department granted limited participant status to the following entities or persons: Lawrence P. Cole, Ph. D.;'F, astern Edison Company /Montaup Electric Company; IRATE, Inc. ("lRATE"); the Honorable Ruth W. Provost; and Unitil/Fitchburg Gas and Electric Light Company. From January 20,1998 through January 29,1998, the Department (
- On January 2,1998, Lawrence P. Cole withdrew his participation in the proceeding.
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- D.P.UJD.T.E. 97-111 Page 4 ;
I conducted seven days of evidentiary hearings at its offices in Boston. l In support of their filing, the Companies sponsored the testimony of seven witnesses: L l Russell D. Wright, president and chief operating officer of the Companies; Robert H. Martin, manager of revenue requirements and contract administration; Henry LaMontagne, manager of L pricing and rate design; Michael R. Kirkwood, director of supply administration; Lisa M. i Carloni, director of marketing for Cambridge and Commonwealth; and Lauren A. Foley, ! l l manager of customer service for Cambridge and Commonwealth. l CISR sponsored the testimony of Timothy Woolf, senior associate, Synapse Energy l Economics. The Compact sponsored the testimony of four witnesses: Robert S. Jones, Selectman, Town of Sandwich; Margaret T. Downey, Interim Assistant County Administrator for Barnstable County; Paul Chernick, president of Resource Insight; and Jonathan Wallach, vice-president of Resource Insight. The Companies, the Anorney General, the Compact, Enron, IRATE, LII, CISR, and SORE submitted initial briefs. The Companies, Acushnet Rubber,5 the Attorney General, the Compact, Enron, LII, and MIT filed reply briefs. CLF and NEEC submitted a joint reply brief. i L t i j - 1 ( 8 Acushnet Rubber is a member of SORE, an intervenor in the proceeding. e m
. 't . .c; D.P.U/D.T.E. 97-111 Page5 IV. OUTSTANDING PROCEDURAL ISSUES A. Motion for Reconsideration ofInterlocutory Order on Procedural Schedule
- 1. Introduction On January 23,1998, pursuant to 220 C.M.R. i 1.10 (10), the Compact filed a Motion for Reconsideration of the Department's Interlocutory Order on Procedural Schedule
(" Compact Motion"). On January 30,1998, the Companies filed a response to the Compact Motion (" Companies' Response").
- 2. Stands-d of Review The Depanment's Procestral Rule,220 C.M.R. I 1.11(10), authorizes a party to file a motion for reconsideration within :wenty days of service of a final Department Order. The
( Depanment's policy on reconsideration a well settled. Reconsideration of previously ' decided issues is granted only when extraoidinary circumstances dictate that we take a fresh look at the record for the express purpose of substantively modifying a decision reached after review and deliberation. North Attleboro Gas Comoany, D.P.U. 94130-B at 2 (1995); Boston Edison Comoany, D.P.U. 90-270-A at 2-3 (1991); Western Massachusetts Electric Comoany, D.P.U. 558-A at 2 (1987). A motion for reconsideration should bring to light previously unknown or undisclosed facts that would have a significant impact upon the decision already rendered. It should not l l attempt to reargue issues considered and decided in the main case. Commonwealth Electric i Comoany, D.P.U. 92-C-1A at 3-6 (1995); Boston Edison Comoany, D.P.U. 90-270-A at 3
- (1991); Boston Edison Comoany, D.P.U.1350-A at 4 (1983). The Department has denied
! I reconsideration when the request rests on an issue or updated information presented for the [
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D.P.UJD.T.E. 97-111 Page 6 k first time in the motion for reconsideration. Western Massachusetts Electric Comnany, D.P.U. 85 270-C at 18-20 (1987); hul gg Western Massachusetts Electric Comoany, D.P.U. 86-280-A at 16-18 (1987). Alternatively, a motion for reconsideration may be based on the argument that the Department's treatment of an issue was the result of mistake or , inadvertence. Massachusetts Electric Comoany, D.P.U. 90-261-B at 7 (1991); New Enoland Teleohone and Telegraoh Comoanv, D.P.U. 86-33-J at 2 (1989); post _on Edison Comoany, D.P.U.1350-A at 5 (1983). .
- 3. Positions of the Panies
- a. The Comoact The Compact contends that the Department should reconsider its January 16, 1998 l .
Interlocutory Order because (1) the issues raised in the filing will radically change the 9 manner in which Commonwealth's customers will receive electric service; (2) Commonwealth has failed to offer a compelling argument for a speedy resolution of the l l proceeding; and l (3) under the Depanment's schedule, the due process rights of the Compact will be violated (Compact Motion at 2). The Compact requests that the Department establish a schedule that would allow parties to conduct funher discovery, to file supplemental testimony, and to engage in l additional cross-examination of Commonwealth's witnesses (it at 5). Further, the Compact
- urges the Depanment to issue an initial order by March 1,1998, and to reserve the right to conduct funher hearings (ii).
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- b.- The Comannias i
- l. The Companies argue that the Compact Motion shoold be denied, because it raises an i
j issue not properly the subject of reconsideration (Companies' Response at 2). The Campanies state that the Department has interpreted 220 C.M.R. I 1.11(10) as limiting i reconsideration to final orders only (it, Elling NYNEX, D.P.U.' 94-50 (Interlocutory Order) l
- at 3, n.3 (July 14,1994)).
i j The Companies further argue that if the Department were to consider the Compact I-Motion ripe for consideration, the Department should deny the Motion because it fails to - satisfy the Depanment's applicable standard for reconsideration (it at 2). According to the Companies, the Compact merely sets forth an argument previously offered by the Ccmpact
. and rejected by the Department that the schedule amounts to a denial of due process (ii).
\
- The Companies also contend that the Compact failed to raise any new facts either during hearings or in direct testimony that would warrant the Department's reconsideration of the procedural schedule (it at 3). Finally, the Companies argue that the Act provides no discretion for the Department to delay a final order until after March 1,1998 (it at 4).
- 4. Analysis and Findinn The Department must first determine whether a motion for reconsideration is l
appropriate in this instance. The Department's Procedural Rule,220 C.M.R. I 1.11(10), authorizes a party to file a motion for reconsideration within twenty days of service of a final Depanment Order. The Compact seeks the Department's reconsideration of the procedural schedule set forth in the Department's January 16,1998 Interlocutory Order. The term
- interlocutory" is defined as something intervening between the commencement and the end !
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i D.P.U/D.T.E. 97-111 Page 8 of a proceeding which decides some point or matter, but is not a final decision of the whole controversy.' Sg Black's I2w Dictionary. Inasmuch as the Order at issue is interlocutory l in namre, and does not make any final disposition regarding the Companies' petition, there is i no basis in the Department's rules for the motion for reconsideration. See Housatonic Water Works Comnanv. D.P.U. 90-284, at 3 (1991). ; The Department's procedural rule is based on the principle of administrative l l efficiency. The Department's ability to make final determination on issues and carTy oint its i regulatory duties would be seriously hampered if it were required to reconsider every preliminary, procedural and interlocutory decision. This principle is also recognized in the Massachusetts Administrative Procedure Act ("MAPA"), G.L. c. 30A. Under the MAPA, l administrative agency actions and rulings which are procedural or interlocutory in nature are not immediately reviewable under G.L. c. 30A, { 14.' Cella, Administrative Law and Practice, Massachusetts Practice Series, Vol. 40, i 1756. Funber, appeals are permitted Is only from final decisions or orders of the Department. G.L. c. 25, f 5. Boston Gas Comoany v. Deoanment of Public Utilities,368 Mass. 780 (1975). Accordingly, in the interest of administrative efficiency and pursuant to the Department's procedural mies, the !
- Department denies the motion for reconsideration.
l Nevertheless, even if the Department were to consider the motion substantively, the l l l l Although the Department is aware of at least one instance where the Department reconsidered an interlocutory order without discussing 220 C.M.R. Q l.11(10), this was departure from our procedural rules that the Department declines to repeat. i I Pursuant to G.L. c. 30A, { 14, any person aggrieved by a final decision of an agency in an adjudicatory proceeding is entitle to judicial review of that decision. ( l
l l D.P.UJD.T.E. 97-111 Page 9 Department would find that the Company has not satisfied the Depanment's standard for j reconsideration. The Depanment finds that the Compact has alleged no unknown or undisclosed facts that warrant the Department's reconsideration. Rather, the Compact merely j reiterates and reargues the issue, raised to the Depanment at the procedural conference and i l addressed in the Interlocutory Order, that the schedule amounts to a denial of due process, y i The Depanment has found that the procedural schedule affords all parties an opponunity for a full and fair hearing in accordance with G.L. c. 30A, i 11. Sag Interlocutory Order at 2-i
- 4. Funher, the Compact has failed to illuminate any mistake or inadvenence that would !
warrant the Depanment's reconsideration of the schedule. B. Motion for Protective Treatment e
- 1. IntroduCli2D
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- l On November 19, l9' 97, the Companies filed pursuant to G.L. c. 25, f SD a Motion i
for Protective Treatment (" Companies' Motion") of the following ponions of the filing: (1) Power Contract Mitigation Repon, designated Attachment 1; (2) the plans for divestiture of purchased power agreements, designated Attachment 2; and (3) the plans for divestiture of generating assets, designated Attachment 3. On Febmary 13,1998, the Companies submitted redacted versions of Attachmuts 1,2 and 3. No pany to the proceeding opposes the Companies' Motion.8 8 j The Department notes that the Companies have entered into non-disclosure agreements with those panies seeking access to the information for which the l { Companies have moved for protective treatment. l
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- 2. Standard of Review General laws. c. 25, i SD provides that the Depanment may protect from public f disclosure trade secrets, confidential, competitively sensitive or other proprietary information Provided in the course of proceedings before the Department. Section 5D also states that
*[t]here shall be a presumption that the information for which such protection is sought is i
public information and the burden shall be upon the proponent of such protection to prove l t the need for such protection." Thus, the burden on the company is to establish the need for protection of the information cited by the company. In determining the existence and extent t of such a need, the Department must consider the presumption in favor of disclosure and the specific reasons that disclosure of the information benefits the public interest. The Berkshire Gas Comnany et al., D.P.U. 93-187/188/189/190, at 16 (1994). (' 3 Positions of the Comnanies l I The Companies argue that disclosure of the infonnation related to the Companies' efforts to reduce the purchased power contract costs would have a chilling effect on the Companies' ability to discuss such reductions in the future (it at 4). Funher, the Companies raise the concern that disclosure of the divestiture solicitations related to the sale l of both their purchased power contracts and generating assets will lower the prices offered for the assets, and thereby harm the Companies' customers by creating higher transition costs (it at 6).
- 4. Amlvsis and Findines i
The Depanment finds that disclosure of the information for which the Companies are ! seeking protection could undermine the Companies' effons to secure lower transition costs I ( l l
D.P.U/D.T.E. 97-111 Page1I for their customers. Affording confidentiality to this information would likely add value to the Companies' assets, and increase their ability to negotiate lower prices for their purchased power contracts. Accordingly, the Department finds that the Companies have provided sufficient reasons to protect the information in accordance with G.L. c. 25, f SD and hereby I grants the Companies' Motion. Accordingly, materials described in the Companies' Motion i will be excepted from public disclosure under G.L. c. 25 6 5D, and G.L. c. 66, i 10 and c.
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4, I cl. 26(a) until the Department's final action on the Companies' divestiture of generating l assets. Protection under i SD will also extend to the following portions of the transcripts: Tr. 3, at 32-60; Tr. 4, at 177-217. I V. STANDARD OF REVIEW The legislature has vested broad authority in the Department to regulate the ownership and operation of electric utilities in the Commonwealth. Srs, g.,.g , G.L. c. 25, il 5,9,18,19, and 20; c. Ill, il SK and 142N; and c.164, fi 1 through 33,69G through 69R,71 through 75, and 76 si att This authority was most recently revised and augmented by the Act. The primary goal of the Act is to establish a new electric utility " framework under which competitive producers will supply electric power and customers will gain the right to choose their electric power supplier" in order to " promote reduced electricity rates." St.1997, c.164, i 1. Among other things, the Act authorizes and directs the Department to " require electric companies organized pursuant to the provisions of [G.L. c.164] to accommodate retail access to genention services and choice of suppliers by retail customers, unless otherwise provided by this chapter. Such companies shall file plans that include, but shall
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~not be limited to, the provisions set forth 'in this section." St.1997, c.164, i 193 (G.L. c.
l 164, IA(a)). Pursuant to this statutory authority, the Department will review a Company's i restructuring plan for compliance with applicable provisions of the Act. i i The Act sets forth explicit directions for the Department's review of restmeturing plans. Plans must contain two key features. First, they must provide, by March 1,1998, a l rate eduction of 10 percent for customers choosing the standard service transition rate from the average of undiscounted rates for the sale of electricity in effect during August 1997, or such other date as the Department may detennine. E Second, each plan must be designed to implement a restructured electric generation market by March 1,1998 by requiring the electric company to offer retail access to all customers as of that date. E l . Plans must also include the following important provisions: , (1) an' estimate and detailed accounting of total transition costs eligible for recovery pursuant to G.L. c.164, i 1G(b); (2) a description of the company's strategies to mitigate transition costs; (3) unbundled prices or rates for generation, distribution, transmission, and other services; (4) proposed charges for the recovery of transition costs; (5) proposed programs to provide universal service for all customers; i (6) proposed programs and mandatory charges to promote energy conservation and l demand-side management;
- (7) procedures for ensuring direct retail access to all electric generation suppliers; 4
} f (8) discussions of the impact of the plan on the Company's employees and the t-
- communities served by the Company; and
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' P D.P.U/D.T.E. 97-111 Page 13 (9) a mandatory charge per kilowatthour for all consumers to support the development and promotion of renewable energy projects; j ' E at i 37 (G.L. c. 25, i 20(a)(1)), i 193 (G.L. c.164, I A(a)). !
i , l The Act directs the Department to allow the implementation of plans, such as the l Companies', filed before the enactment date: "An electric compaay that has filed a plan which substantially complies or is consistent with this chapter [LL, G.L. c.164, as ' amended] as determined by the [D]epanment shall not be required to file a new plan, and the 4 [D]epanment shall allow such plans previously approved or pending before the [D)epartment to be implemented." E at i 193 (G.L. c.164, i 1 A(a)). The Depanment is governed by the statutory directives in determining whether a plan should be approved for implementation. In doing so, the Depanment applies a two-pan standard of review. First, for those sections of a plan governed by G.L. c.164, the Depanment must determine ' whether the plan "substantially" complies or is consistent with the Act as it amends G.L. c. 164. For all other features of the plan, the Depanment must determine unqualified compliance of those features with applicable provisions of the Act. We first state the standard of review in determining whether a plan substantially complies or is consistent with G.L. c.164. The statute directs the Department to approve any plan that was filed before enactment, provided it substantially complies or is consistent with G.L. c.164, as amended. E at i 193 (G.L. c.,164, i 1 A(a)). Although the word "substantially" is not defined in the Act, its meaning may be determined from usage and context. G.L. c. 4, f 6, cl. Third. In applying this standard, the Department considers that an action "substantially complies" if it achieves " compliance with the essential requirements" I j of G.L. c.164. Black's law Dictionary, Sixth Edition (1991). An action that is compatible
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I D.P.UJD.T.E. 97111 Page 14 i with and not contradictory of a statute is " consistent" with the statute. Ji The use of these i terms in the disjunctive leads to the conclusion that the I.egislature has given the Department a measure of discretion to effect the important public purposes of the Act. In addition, the Legislature has mandated swift implementation of the Act (LL, before March 1,1998). Bet.ause the phrase "substantially complies or is consistent with" is imprecise, the . Department supplements its understanding of the words in the statute (customarily, "the principal source of insight into legislative purpose" Bronstein v. Prudentini Inmenace Co., 390 Mass. 701, 704 (1984)), with a consideration of "the statute's purpose and history." Sterilite Com. v. Continental Casualty Co.,397 Mass. 837 at 839. A more limiting l interpretation would defeat the Act's purposes and fail to give "a fair consideration of the conditions attending its passage." Fickett v. Boston Fireman's Relief Fund,220 Mass. 319, ( - 1 320 (1915). Next, we address the standard of review for those sections of a restructuring plan that are not governed by G.L. c.164. In such instances, the Department must require unqualified compliance with the Act's mandates. Thus, in reviewing sections of a restructuring plan not governed by G.L. c.164, the Department must determine that those sections conform to the Act before it may approve a restructuring plan. 4 1 I i
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l i D.P.U/D.T.E. 97-111 ' Page 15 VI. ISSUES : i A. Standard Offer L 1. Standard Offer and Comnetitive Pricinn
- a. The Act
[ The Act requires that a distribution company provide a standard service transition rate i l for the period from March 1,1998, to January 1,2004, at prices and terms approved by the i Department. St.1997, c.164, i 193 (G.L. c.164, i IB)? The Act requires that distribution ; companies purchase electricity for standard offer service after a competitive bid process. E ! The Act further requires that, if and to the extent that retail prices for standard offer power are below the wholesale costs of standard offer power, the Department shall investigate i whether it is appropriate to extend, through new legislation, a comparability credit for non- ! ( , i standard offer customers. E at { 308. (The comparability credit is a deferral mechanism i l for competitive suppliers intended to be comparable to the distribution company's deferral I mechanism under the standard offer.) ! b. The Plan l l The standard offer implements several objectives of the Plan. The standard offer provides a ten percent rate reduction for those customers who elect standard offer service. The standard offer also facilitates the transition to retail competition by establishing a The standard service transition rate is the generation component of the service package that is to provide the 10 percent rate reduction beginning on March 1,1998. It is typically referred to as the " standard offer" or " standard offer rate," so that, for L example, a reference to a standard offer price of 2.8 cents per KWH would refer to the i { price for the generation portion of the service package that will provide the 10 percent rate reduction. l
,: _ . . . l D.P.U/D.T.E. 97-111 Page 16 schedule of rates that increase over time, thereby encouraging customers to move into the competitive market durm' g the seven year term of standard offer service. The Plan provides 1
that standard offer service be secured through a competitive bid process. The retail price for standard offer service is 2.8 cents per KWH in 1998 and increases each year to a maximum of 5.1 cents per KWH in 2004.
- c. Positions of the Parties
- i. . Enron. The Cornnmet. and SORE Enron, the Compact, and SORE argue that standard offer prices are well below market price forecasts, a condition which will inhibit competition. These parties contend that i
the low standard offer prices, especially the price of 2.8 cents per KWH in 1998, will i prevent true retail access from occuning on March 1,1998, and thereby undermine the. legislature's mandate. The Compact contends that the rates are purely arbitrary, based on standard offer rates other companies filed, and that the Companies have not performed any calculations to determine appropriate rates for their service territories (Enron Brief at 3, Compact Brief at 12, SORE Brief at 13). The Compact provided evidence that the costs of providing standard offer service are higher than the proposed prices (DTE-RR-23, DTE-RR-24, Exh. CL-84, p. 25, n. 21). The l Compact and Enron recommend that the Department issue an order that includes a 4 cents per KWH standard offer price in 1998. (Compact Brief at 12, Enron Reply Brief at 3). This is below the 4.3 cents per KWH cost of providing standard offer service calculated by I \ the Compact's expert witnesses, Paul Chernick and Jonathan Wallach. The Compact argues, j however, that 4 cents per KWH is the lowest price supported by the record (Compact Brief i
4 D.P.U/D.T.E. 97-111 Page 17 at 17). The Compact argues that the record in this case suppons a higher standard offer price while the record in previous restmeturing cases, such as D.T.E. 96-23, did not (it at 15). The Compact and Enron argue that the Department should not approve the standard offer rates in this case based on its previous findings because of the different factual record in this case (Compact Brief at 15). SORE makes a similar argument and claims that the prices for firm delivery into the Commonwealth service territory have recently ranged between 3.0 and I 3.2 cents /KWH (SORE Brief at 13). j i ii. Attorney General The Attorney General argues that the Companies' rate schedule for standard offer ! I service, although consistent with restructuring plans approved by the Department, should not 1 ( be accepted since the Companies' own evidence supports a higher market price of power. The Anorney General supports the elimination of both the difference between wholesale and 1 retail prices in 1998-2000 and future additions to any deferred cost balances (Attomey General Brief at 10), iii. Comoanies The Companies argue that the proposal standard offer service ' cmsistent with the Act and with other plans that have been filed and approved by the Department. The Companies argue that the Plan provides a 10 percent rate reduction to standard offer customers, using standard offer rates that the Department approved in the MECo, EECo, and BECo restructuring plans (Companies Reply Brief at 10). The Companies argue that standard offer prices should not be set at market levels [
4 D.P.UJD.T.E. 97-111 Page 18 because standard offer service is to provide a transition to retail competition. The l Companies argue that both the Act and Department precedent in D.P.U. 96-100 and the other restructuring plans recognize the transitional nature of standard offer service l (Companies Reply Brief at 11). The Companies claim that maintaining similar or identical standard offer prices among the various distribution companies will give customers in all : service classes and territories roughly similar access to competitive alternatives from suppliers (Companies Brief at 28). The Companies also argue that setting standard offer prices at market levels would obviate the need for default service, since default service is indexed to market prices. The Companies argue that neither the I.egislature nor the Department intended to elimitate default service and replace it with standard offer service (11 at 28). ( ' The Companies assert that the standard offer price stmeture maintains the Companies' ! financial stability. They argue that a standard offer price of 4.5 cents /KWH for l Commonwealth would require a reduction in the access charge of 1.7 cents /KWH which would lead to an underrecovery of transition costs of approximately $60 million in 1998, and i that Commonwealth would soon reach the $75 million limit of its borrowing capability l (Exh. DTE RR-22, Companies Reply Brief at 23). The underrecovery would accumulate in l a recone',liation account together with interest equal to the carrying charge for the fixed componets of the access charge, which is 13.51 percent (Exh. CEC-1. Tab H at 4,9, sch.1, 9 of 12). The base access charge will be adjusted at the end of every year to allow recovery ! to the extent permitted (it at 9). Any amounts in the reconciliation acccunt that would i
- . increase the access charge above the allowable level will be deferred to the following year, 1(
1 D.P.UJD.T.E. 97-111 Page 19 ! l and will earn a return as described above (it at 9). The Companies contend the underrecovery would put them at financial risk, as well as result in increased costs to customers (Companies Brief at 29).
- d. Am1vsis and FiEllDgi
! The evidence in the record supports a finding that the Plan provides standard offer i service to customers beginning on March 1,1998 and continuing through December 31, 2004, and that it does so at appropriate prices that, along with the other unbundled components of the rates discussed below, provide a ten percent rate reduction from rates in effect during August,1997. The Plan also provides that standard offer service be procured through a competitive bid process.80 The Companies' proposal thus meets the requirements of the Act. l The Department has considered and rejected in other restructuring cases the arguments against the standard offer pricing made by Enron, the Compact, SORE, and the Attorney General (who supponed identical standard offer prices in three other plans, including one approved less than two months ago). These intervening panies argue that the standard offer price is below current and projected market prices and thus will inhibit l l competition. They argue that this record contains more evidence than in other cases that market prices are at or above 3.0 cents per KWH in 1998, so that the Department can and should set the standard offer price above that level for 1998, thereby encouraging a larger percentage of customers to leave standard offer service for competitive suppliers in 1998. i , The Companies' auction to procure competitive supply of standard offer service I resulted in no bids. The Companies have not determined how they may address the
- results of the unsuccessful auction. These facts are discussed further below.
l -
~
D.P.U/D.T.E. 97-111
-{ Page 20 The estimates of current market prices range from 3.0 cents per KWH (from SORE) to 4.6 I cents per KWH (the Compact).
The Department rejects these arguments in this case for the same reasons we rejected them in the previous restructuring cases. First, the Act emphasizes the transitional nature of I the standard offer. Ess, g&, St.1997, c.164 i I (G.L. c.164, i IB(b)). The Act refers to l the standard offer as the " standard service transition rate," which is to be in place for "a transition period of seven years" and, in conjunction with the other components of unbundled rates, provides a 10 percent rate reduction. The findings and declarations of the Act show that the Legislature intended an expedient and orderly transition from regulation to ! competition in the generation sector. Interpreting the Act as requiring that standard offer ! ( prices be equal to or greater than wholesale market prices would ignore the Legislature's clear directive to provide an orderly transition to competition in the generation sector. The l Companies' proposal does provide an orderly transition, as the standard offer price increases I steadily over time, which will provide an increasing incentive for customers to move to l competitive suppliers. i Second, the Companies' standard offer price schedule accomplishes other important ) goals enunciated in the Act that would be jeopardized by the intervenors' proposals. Recovery of net, non-mitigable transition costs "on a non.bypassable basis and in a manner that does not result in an increase in rates to customers of electricity corporations" is one such i goal. St.1997, c.164, il 1(t) and (u) (G.L. c.164, i 1G). The intervenors' proposal jeopardizes this goal in this case because of the immutable characteristics of the Companies' fj rate structure. The record shows unequivocally that an increase in the standard offer price for
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. l i
D.P.U/D.T.E. 97-111 Page 21 f
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1998 and thereafter would force immediate deferral of a portion of the Companies' access ! charge, which would likely raise rates and could put at risk the Companies' orderly recovery : l of transition costs. , l l An example illustrates this point. Under the proposal in the Plan, the Companies could procure standard offer service in 1998 for a wholesale price up to 3.2 cents per KWH, ! at a time when the standard offer price is 2.8 cents per KWH. The Plan calls for the i ( difference between the wholesale and standard offer prices,4 mills, to be deferred for later :
- collection, such deferral being necessary in order to achieve the 10 percent rate reduction 1
required by the Act. The deferred amount would accrue interest at a rate based on customer deposits" (about 6 percent). If the standard offer price were raised to 3.2 cents, however, a conesponding 4 mill decrease in the access charge would be required in order to achieve the ( ! 10 percent rate reduction. This transition cost deferral would accrue interest at a rate equal to the Companies' rate of return on capital (about 13 percent). This higher carrying cost l would increase the total amount of transition costs customers would be required to pay. In its guidelines for standard offer service in D.P.U. 96-100, at 137, the Department stated that l the provision of standard offer service should not result in additional stranded costs for distribution companies. The Department declines to depart from that goal here. The L Department will not force customers to pay higher interest on deferred transition costs in the i name of enhancing short-term competitive access to the retail market on more favorable terms. Full competition in generation is the goal, but the Legislature prescribes that it be 1 4 i i f Interest on customer deposits is equivalent to the rate paid on a two-year treasury note for the preceding calendar year. i
,..g l
l f D.P.U/D.T.E. 97-111 - Page 22 ( reached through an " orderly transition." i l Third, the Act provides the Department with authority to address the potential ! situation about which the intervenors take issue. As the Depanment has noted with respect i to other restmeturing plans, in the event that the Companies are able to sell their generation i i l facilities and entitlements on favorable tenns, the Companies may decrease the access charge l l and increase standard offer prices accordingly at that time." D.T.E. 96-23, at 19. Further, l l ' the Department is fully aware of the remedy provided by the Act if wholesale prices remain above the standard offer price: l l Cognizant of the potential competitive problem posed by standard offer rates below market rates, the Act requires that, if the retail prices for standard offer power are below the wholesale price, then the Department shall investigate whether it is appropriate to extend, through new legislation, a comparability credit (a deferral mechanism for competitive suppliers intended to be comparable to the Company's ( deferral mechanism under the standard offer) to non standard offer customers. St.1997, c.164, 6 308. Accordingly, the Department will monitor the relationship between standard offer prices and wholesale costs and will initiate an investigation in the future if circumstances warrant. D.T.E. 96-23 at 19. The same approach is appropriate in this case. In fact, if the Department were to adopt the intervenors' position that standard offer prices must always be equal to or greater than market prices, Section 308 of the Act would be rendered mere verbal surplussage as the condition precedent to its invocation (namely, standard offer prices lower than market prices) would never exist. Funher, the Act allows for the possibility that standard offer prices may be below market prices without any action being required by the Department. Section 308 provides that upon such a finding the Depanment shall investigate ![ " For this reason the Department does not find compelling the Companies' argument that the standard offer should be consistent across the state. 1 l'
,'.. .,' l 1
1 D.P.UJD.T.E. 97-111 Page 23 l 5 whether or not to extend a comparability credit through additional amendment to G.L. c. l 164. 1 Based on the foregoing, the Department finds that the standard offer price and terms proposed by the Companies are in substantial compliance and are consistent with G.L. c. l 164, are approved, and should be implemented on March 1,1998.
- 2. Standard Offer and Bachtan Service
- a. Intenduction Backstop service is the electricity supply provided by a purchaser of a distribution company's generating assets or purchased power contracts to supply a distribution company's standard offer customers. If the purchase and sale agreement includes the backstop service obligation, the purchaser is obligated to provide the electricity supply at guaranteed wholesale
!( 2 rates. The obligation to provide backstop service arises only if a distribution company's
- standard offer auction does not generate sufficient resources to serve all its standard offer customers. The Act does not address the issue of backstop service.
1 i j b. The Plan ' i 1 l The Plan provides a schedule of rates that serve as the maximum wholesale prices that the Company will pay to standard offer suppliers. The rate schedule begins at 3.2 cents per l KWH in 1998 and increases to 5.1 cents per KWH in 2004 2005_(Exh. CEC-1, at 33). The i , I l
' Companies plan to backstop their standard offer service obligation at predetermined prices al
- part of their divestiture of generation resources (Exh. CEC-1, at 30,33). The Companies' purchaw and sale agreements through the divestiture process will include an obligation that l purchasers of generation and purchased power contracts provide electricity to serve the l
D.P.U/D.T.E. 97-111 Page 24 Companies' standard offer service. (Tr. 2, at 33-34; Tr. 4, at 193). That obligation will be invoked if a standard offer auction does not result in a sufficient supply of standard offer service (Tr. 4, at 125-127; Tr. 5, at 131-132). In the meantime, the Cmpales will use their generation resources to supply standard offer service (ii).
- c. Positions of the Par 1[gg
- i. Compact and Enron The Compact and Enron contend that the price caps on backstop service are below market and needlessly depress bid prices for generation assets and power purchase contracts, resulting in increased transition costs that customers will pay. The Compact's expert witnesses (Chemick and Wallach) submitted an estimate of the effect that the backstop obligation will have on the sale price of the Companies' generating and power purchase assets (DTE-RR-23). The results show losses that purportedly range from tens of millions to hundreds of millions of dollars. (Compact Brief at 20-22; Enron Brief at 6-8).
Enron points out that on cross-examination the Companies admitted that some bidders may view the backstop obligation as a negative feature and therefore decrease their bid price (Exhibi'. ECT 1-11; Enron Brief at 7). The Companies also acknowledged that bidders with the most optimistic view of the market would be affected the most by the backstop obligation since the Companies anticipate that the most optimistic bidder would purchase the generation resources (Tr.2, at 64-66). The Compact recommends that the Companies be directed to conduct their auctions to solicit separate bids which include and exclude the backstop obligation. Through such an l auction, the Compact claims that the Companies will be able to maximize the toal economic (
J. .; . . ' D.P.U/D.T.E. 97-111 Page 25 benefits for all ratepayers (Compact Brief at 22). ii. The Cor]onnies in opposition to Enron and the Compact, the Companies' contend that it is not possible I to determine whether the backstop obligation will depress the value of the Companief l generation resources. The Companies maintain that there are too many unknown i assumptions and variables that play into bidders' decisions for Enron and the Compact to predict the outcome. Variables include perceived future market prices, sales forecasts, pattern and use for standard offer load, and a "first strike" advantage that bidders may gain by capturing initial market share through supplying standard offer service even if bidders incur a loss (Companies Reply Brief at 17). The Companies state that, even assuming that the backstop obligation could depress the value, it would not be to the detriment of the customers. To the extent that the backstop obligation diminishes the residual value credit, i then the customers would necessarily receive additional benefits through a lower-price - standard offer (Id.). The Companies also argue that the Department should approve the , proposal for supplying standard offer service through a backstop provision as part of their auction of generation resources because of the precedent set with previous orders (11). l
- d. Am1vsis and Findines ,
in opposing the backstop p rovision, the Compact and Enron presented evidence that in i the early years of the transition period, the standard offer price may be lower than the i market price. Other evidence, such as that presented by SORE, supports a finding that this may be true at most for 1998 and that, beginning in 1999, the standard offer price would be above projected market prices. The Companies also presented testimony, as was the case
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l l l D.P.UJD.T.E. 97-111 Page 26 with respect to standard offer pricing, tbt bidders may take many factors into account in
-detennining their bids for the Companies' generating plants and entitlements, that the relationship between the standard offer price and market prices in 1998 is only one of many such factors, and that some bidders may view the backstop obligation as a benefit while others may not.
The backstop provision would oblige the purchasers of the Companies' generating i assets and entitlements to supply power for standard offer service at prices that would not exceed the wholesale price caps set forth in the Plan (Exh. CEC-1, Tab D at 33). The backstop abligation guarantees a supply of power for standard offer service at known wholesale prices, thus providing the Companies' customers with the equivalent of insurance l against wholesale prices for standard offer service that might exceed the wholesale price caps ( in the plan. Providing such rate stability will ensure that the rate reductions required by the Act will continue through the transition period without causing greater deferrals either of standard offer costs or transition charges should wholesale prices to supply standard offer service exceed the Compact's and Enron's projections. The Compact and Enren have not presented sufficient evidence that removing a feature of the Plan that provMes such rate stability will bring any benefit to customers. This is true in two respects. First, the evidence that the backstop obligation will depress the value in divestiture of the Companies' generating assets and entitlements is inconclusive, at best.
'Ihe Compact and Enron rely on an exhibit prepared by the Compact's expen witnesses that purpons to estimate the impact of the backstop obligation on the sale price of the Companies' assets (DTE RR-23). The Compact's witnesses based their calcult.tions on several
( I
i D.P.UJD.T.E. 97-111 Page 27 ( ' assumptions: first, that the competitive market price for power would be greater than the standard offer wholesale price caps through all seven years of the transition period; second, ; that a potential purchaser of the Companies' assets would reduce his or her bid by an amount equal to the net present value of the difference between the competitive market price and the i wholesale price cap, times the total amount of standard offer sales; and third, that the total dollar loss from the backstop is based on a constant percent of sales served under standard offer service for each year during the transition period, (LL,100 percent of sales from standard offer service for each year of the transition period) (DTE RR-23, at Table 1). These assumptions would have to be true for the Compact's argument to be supponed by the record. The record does not supper
- all of these assumptions. As discussed above
.with respect to standard offer service, the record contains several estimates of market price, some of which show that the standard offer wholesale cap price is above the projected market price for most or all of the transition period. On this point, the record is, at best equivocal (Exh. AG-8; SORE Brief at 11-13). The Cor,a.tct's other two assumptions find no suppon -
in the record. No witness refuted the Companies' iustimony that bidders may take factors into account other than a nominal difference between one projected market price and the wholesale price cap. The Depanment notes that in some scenarios presented in DTE-RR-23, Table 1, the purponed depression in value related to the backstop, even accepting all of the Coinpact's assumptions, is relatively small and could easily be exceeded by such strategic factors as a "first strike" advantage discussed by the Companies' witnesses. Finally, the Compact provided ne suppon for DTE-RR-23's assumption that the standard offer will constitute a constant percentage of total retail sales throughout the transition period, a
m D.P.U1D.T.E. 97-111 Page 28 simplifying assumption that renders suspect the remaining analysis in Table 1. DTE-RR-23 comains estimates of the loss due to the backstop provision, rangir;g frcin $9,017 (in the :
\
event the standard offer service constitutes 10 percent of the retail sales during each year of ! l i the transition period, and the market price is equal to the Companies' estimate in Exh.AG-8) to $415,%5 (in the event the standard offer service constitutes 100 percent of retail sales - during each year of the transition period, and the market price is as the Compact's witnesses t estimate). The Compact's witnesses provide no basis for determirdng what the actual impact might be, nor does this range of estimated loss from the backstop take into account the value bidders may place on the strategic factors discussed above or the value to customers of j procuring standard offer service at known price', throughout the transition period. I The Depanment will not trade the rate insurance and stability provided by the , backstop oblige. tim for purported increases in the sale price of the Companies' assets that are not supported by substantial evidence in the record. The cap on the wholesale rates, which is part of the backstop obligation, will allow the Companies to procure electricity for standard offer customers at set prices regardless of the future wholesale price of power. The cap protects customers from the rate increases that would occur if future wholesale prices exceed the cap. The Department finds that the backstop provision provides a benefit to customers by reducing price volatility and risk. The evidence provided by the Compact and Enron in this ! case proves no offsetting benefit that would support elimination of the backstop obligation. l Therefore, the Depanment finds that the divestiture of the Companies' generating assets and entitlements subject to the backstop obligation substantially complies with G.L. c.164. L ( l l
, . . . ~ _ . _ _
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l i D.P.UlD.T.E. 97-111 Page 29 B. Retail Delivery Rates and Rate Reductions 1
- 1. Introduction j
- a. The Act l i
The Act specifies that the retail access date (" RAD") will be no later than March 1, l 1998. St.1997, c.164, f 193 (G.L. c.164, i 1A). The Act further states that beginning { on March 1,1998, a distribution company must design rates, so that (1)'all customers on
]
I standard offer service will receive at least a 10 percent reduction in the cost for electric service when compared to the undiscounted rates in effect during August 1997 or such other i i date as the Department may determine to be representative of 1997 rates for such company;
)
and (2) all rates are unbundled to reflect separately the charges for distribution service, transmission service, transition service, standard offer service and any other charges added pursuant to any provision of law. St.1997, c.164, i 193 (G.L. c.164, if IB, ID).
- b. The Plan The Plan includes rates designed to comply with the Act by implementing the
{ following steps. First, Cambridge and Commonwealth ach developed an unbundled cost of service study ("COSS") using calendar year 1995 adjusted costs (Exh. CEC-1, Tab D at 13, ' 17; Tr.1, at 62). Both Cambridge and Commonwealth adjusted their COSS to reflect the base rates, fuel charge, and conservation charges that were in effect in August 1997 (Exh. CEC-1. Tab D at 13,17; Exh. DTE-11; Exh. DTE-21; Tr.1, at 66-90)." Also, the ! l Instead ofincluding the 6.5 cents per KWH fuel charge that customers were billed during 1997, Commonwealth used a fuel charge of 6.7 cents per KWH which was the i~ amount it was allowed, but did not choose to, charge under a Fuel Charge Stabilization Agreement with the Attorney General. This matter is discussed in Section VI.B.2.b.
. l l D.P.U/D.T.E. 97-111 Page 30 costs functionalized as transmission were replaced with the Federal Energy Regulatory i Commission ("FERC")-based transmission revenue requirement (Exh. CEC-1, Tab D at 15, l 18). According to Cambridge and Commonwealth, the COSS uses methods for l
j functionalization and allocation that were approved by the Department in their last rate cases (it, Tab D at 14,18, , Eiling Cambridae Electric Linhr Comoany, D.P.U. 92-250 (1993); commonwealth Electric Comoany, D.P.U. 90-331(1991). 1 Once the unbundled COSS were developed, Cambridge and Commonwealth each calculated a uniform transition charge. The difference between 90 percent of the total revenue requirement based on August 1997 revenue levels and the sum of the standard offer, transmission, distribution, and customer components, determined the proposed uniform transition charge (it). Both Cambridge and Commonwealth determined the revenues for the k. standard offer component by multiplying the proposed standard offer rate of 2.8 cents per KWH by the adjusted 1995 KWH sales. The transmission component was based on the FERC-based Lansmission revenue requirement and the distribution and customer components were obtained from the 1995 COSS. This calculation produced a uniform transition charge of 2.73 cents per KWH for Cambridge and 4.26 cents per KWH for Commonwealth (11). The next step in the rate design process was to determine the design of the individual unbundled rate schedules. First, the total target revenue for each rate class was set at 90 percent of the class's August 1997 revenue requirement (ii). The Standard Offer charge i
- was set at 2.8 cents per KWH for each rate class; the uniform transition charge was set at !
l ( l '
_.l D.P.U/D.T.E. 97-111 Page 31 2.73 cents per KWH for each of Cambridge's rate classes" and 4.26 cents per KWH for each of Commonwealth's rate classes; and the transmission charge was determined by using the FERC-based revenue requirement on the basis of either KWH, if the rate is non-demand billed, or KW if the rate is demand billed (ii, Tab D at 16). The customer charge for each rate class was set at 90 percent of the class's customer charge in effect in August 1997. For those classes that are billed a demand charge, the Companies set the distribution demand charge at the difference between 90 percent of each class's demand charge in effect in i August 1997 and the sum of that class's transition demand charge and transmission demand
)
charge (ii). Lastly, the remainder of the total target revenue for each customer class was collected through the distribution charge on a KWH basis (ii).
, Cambridge and Commonwealth propose rates that would unbundle existing tariffs into k
generation, distribution / transition and transmission components (ii. Tab D at 9). Both Companies propose to eliminate the fuel charge, conservation charges, and energy conservation service charge on March 1,1998 (it, Tab D at 9,10). The Companies propose to add a transmission cost adjustment and a transition cost adjustment to their delivery service rates (it, Tab D at 10). For customers who do not have a competitive supplier, the Companies propose to make available standard offer service and default service (ii). I Cambridge proposed to include a portion of the transition charge as part of the distribution demand charge in those instances where the current energy charges are low i when compared to the proposed standard offer charge and transition charge.
i D.P.U/D.T.E. 97 111 Page 32
- 2. Ten Percent Rate Redusli2D a
( Introduction Two issues have been raised regarding the calculation of the 10 percent rate reduction: (1) whether Commonwealth is using the appropriate baseline fuel charge from I which the 10 percent rate reduction is calculated; and (2) whether the Companies may use : l deferrals in order to meet the 10 percent rate reduction.
- b. Commonwealth's Baseline Fuel Charge Commonwealth proposes to use a fuel charge of 6.7 cents per KWH as a component I
of the baseline rates from which the 10 percent rate reduction is calculated (Exh. CEC-1, j Tab D at 13). The fuel charge that appeared on customers' bills for all of 1997 was 6.5 cents per KWH. Srs Commonwealth Electric Comoany, D.P.U. 96-3D (1997); (. ' Commonwealth Electric Comoany, D.P.U. 97-3A (1997); Commonwealth Electric Comoany, D.P.U. 97 3B (1997); Commonwealth Electric Comoany, D.P.U. 97-3C (1997).
- i. Positions of the Panies 1
(A) The Attorney General The Attorney General assens that Commonwealth's proposed post-retail access rates
}
do not reflect a 10 percent reduction from the rates in effect in August 1997 because the rate reduction is based on rates that were never in effect (Attorney General Brief at 9). The Attorney General also staes that Commonwealth's argument that the required reduction should be measured against some rate that "could have been" in effect should be rejected l (ii). Further, the Attorney General argues that no other rate than the 6.5 cents per KWH fuel charge in effect during August 1997 can be more representative of 1997 rates since it (
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,, l i
i . D.P.U/D.T.E. 97-111 Page 33
- was in effect for the entire year (ii).
l (B) The Comnanies l The Companies state that Commonwealth had the discretion to increase the fuel charge from 6.5 to 6.7 cents per KWH in 1997 according to the Fuel Charge Stabilization l i l Settlement (" Stabilization Settlement") that was signed by the Attorney General and ! Commonwealth and approved by the Depanment in Commonwealth Fiactric Comoggy, l D.P.U. 94-3A (1994) (Exh. DTE-5). Since Commonwealth was entitled to recover 6.7 cents per KWH, Commonwealth argues that the 6.5 cents per KWH fuel charge represents a l l discount from the approved level of the fuel charge (ii). Therefore, the Companies argue that since the 6.7 cents per KWH fuel charge is an "undiscounted" rate, it should be used as ! the baseline for the calculation of the 10 percent rate reduction and complies with the Act (.
~
(Companies Brief at 30). The Companies state that the 6.7 cents per KWH fuel charge is representative of 1997 rates for two reasons: (1) it is the amount permitted under the Stabilization Settlement; and (2) it is consistent with the actual fuel cost incurred during the applicable quaner of 1997 (Companies Reply Brief at 28). Therefore, the Companies argue that they have used an appropriate, undiscounted and representative rate, consistent with the Act, to compute the 10 percent rate reduction (it). ii. Analysis and Findinas The Companies argue that the 6.5 cents per KWH fuel charge was a discounted rate, I since Commonwealth had the ability to increase its fuel charge to 6.7 cents per KWH in I 1997 under the Stabilization Settlement. Commonwealth indicates that it intends to recover l the entire amount of the current under-recovery in the fuel charge account, including the ; (' I i l l
< 4
. D.P.U/D.T.E. 97-111 Page 34 amount that resulted from the fact that Commonwealth did not increase its fuel charge to 6.7 cents per KWH in 1997. Commonwealth, however, has discounted tariffs currently in effect, such as Rate G-3 (ED) (the Large General Economic Development Rate). The witness for the ComparJes stned that Commonwealth has no intention of seeking recovery of the lost revenues that resulted from these discounted rates (Tr. 3, at 154). Because Commonwealth will not recover the lost revenues from other discounted rates but will later recover the fuel charge under-recovery, the Department finds that Commonwealth's use of a 6.5 cents per i
KWH fuel charge in 1997 was not a discount. Therefore, the Department finds that when i Commonwealth calculates its 10 percent rate reduction, it shall use a fuel charge of 6.5 cents l per KWH as a component of the baseline, August 1997 iates." The Act gives the Depanment the discretion to determine the ' representative
- 1997
(' rates from which the 10 percent rate reduction is calculated. There are two factors that go i into determining what is a " representative" rate: (1) whether that rate was actually charged on customers' bills; and (2) whether that rate is subject to later reconciliation and recovery. According to the Stabilization Settlement, Commonwealth was allowed to charge a fuel charge of 6.7 cents per KWH in 1997. However, Commonwealth decided to maintain a fuel charge of 6.5 cents per KWH in 1997 and defer, for later recovery, the difference between the 6.5 and 6.7 cents per KWH fuel charge. 1 L During the proceedings, Commonwealth stated that it will have an over-recovery in its fuel charge account of approximately $10 million due to the proration of the fuel ! charge during the March billing cycle. Commonwealth requested that it be allowed to begin to return this money to ratepayers in the form of a credit on customers' bills starting March 1,1998. The Depanment rejected this request in a separate docket, ! I D.T.E. 98-13, on February 20,1998. ; i
- l l
' D.P.U/D.T.E. 97-111 Page 35 The Department differentiates its finding here from the Department's finding in Western Massachusetts Electric Comoany, D.T.E. 97-120 (1998), where we held that the j rate actually charged was not representative. The charge at issue in D.T.E. 97-120 was a j temporary credit on customers' bills during 1997 which was due to expire, coincidentally, on l February 28,1998 and was not subject to any kind of reconciliation and later recovery. The ,
c!wge at issue in this proceeding, however, is subject to reconciliation and later recovery. Indeed, Commonwealth has every intention and is entitled to recover the full amount of the under-recovery that resulted from its decision to charge 6.5 rather than 6.7 cents per KWH for the 1997 fuel charge. Therefore, the Deparunent finds that the 6.5 cents is the rate 1 representative of 1997 fuel charge rates from which the 10 percent discount should be calculated. (" -
- c. The Comoanies' Use of Deferrals
- i. The Comoanies' Prooosal The Plan provides that some costs may be deferred from year to year to achieve or maintain the rate reductions that the Act requires. These deferrals could take several forms.
If the Companies' actual transition costs during a given interval exceed the transition charges collected during that interval, the Companies will defer the difference for collection through a reconciliation account (Exh. CEC-1, Tab G at 7; Tab H at 9). During years in which the l wholesale price of the standard offer exceeds the retail price, the Companies may defer the I difference between the two if necessary to achieve a 10 percent reduction from rates in effect (
~ - - - -_.
l D.P.U/D.T.E. 97-111 Page 36 l in August 1997.8' If there is a balance remaining in the deferral accounts after the transition ; i petiod, the Companies propose to recover those amounts at that time (RR-ECT-2). If the ; deferrals exceed the Companies' bonowing limits in a given year, the Companies would seek f Department approval to immediately impose a surcharge to reduce the amount of deferrals i below the borrowing limits (Exh. CEC-1, Tab D at 20-21; Exh. DTE-28). ! ii. Positions of the Panies i Enron argues that the proposed defenals are inconsistent with the Act; that the Act j i calls for rate reductions; and that "[a]s a matter of simple English, a reduction is not the l
\
same as a deferral" (Enron Brief at 9). Enron argues that a company that cannot achieve the required rate reductions without deferrals must invoke G.L. c.164, i 1G(c), which states: i If, after the submittal of a restructuring plan to the [D]epartment j ~ ( pursuant to section 1A, a distribution company claims that it is unable to meet a price reduction of 10 per cent... pursuant to subsection (a) of
)
section 1 A and subsection (b) it shall petition the [D]epartment to ' explore any and all possible mechanisms and options within the limits of the constitution which may be available to the [D]epanment to achieve compliance with the provisions of this section . . . The Companies respond that the Act does not prohibit deferrals, which are a "well-established regulatory rate-making practice" (Companies Reply Brief at 19). They argue that 1 j Enron has confused rate reductions, which are required by the Act, with cost reductions, , which are not (ii). Finally, the Companies argue that the Depanment should approve the I use of deferrals here in order to avoid placing the Companies in a " confiscatory situation or 1 i extreme financial distress" (id,). i 4 1 ( Such would be the case in 1998, during which the retail standard offer price is 2.8 cents per KWH and the stipulated maximum wholesale price is 3.2 cents per KWH.
D.P.UJD.T.E. 97-111 Page 37 ( ' iii. Annivsis and Findines Deferrals are a well-established regulatory iatemaking practice, wh'ch the Act does not forbid. The Act, in fact, explicitly allows deferrals in the event the Depanment approves, after further legislation, the implementation of a comparability credit. St.1997, c. 164,6308. They are a reasonable mechanism for companies to provide the mandatory rate reductions during the transitional period of the standard offer while ensuring, to the extent practicable, that the companies recover costs to which they are entitled. The Act is silent on the Company's rate structure beyond the seven-year transition period, and to interpret it as forbidding recovery after that time could lead to a confiscation of the Companies' property in violation of the fifth Amendment to the United States Constitution. Bluefield Water Works v. West Virginia 262 U.S. 679,688 (1923) (prohibiting confiscatory ratemaking by entitling utilities to collect reasonable operating costs and providing an opportunity to earn a just and reasonable return on investment). The Act i must be interpreted, if at all possible, so as not to render it contrary to the terms of the Constitution. Commonwealth v. S.S. Kresne comoany,267 Mass.145,148 (1929); Bay.gs
- v. City of Brockton, 313 Mass. 641, 645-646 (1943). In so interpreting the Act, the Department finds that the Companies cannot be precluded from collecting all of the reasonable costs incurred in providing standard offer service at the mandatory rate reductions, nor can they be precluded from recovering the transition costs explicitly allowed them by the Act. Federal Power Commission v. Hooe Natural Gas Comoany,320 U.S. 591, 605 (1944). This is so even if that recovery occurs after the transition period.
(
)
l
- D.P.UJD.T.E. 97-111 Page 38 The Department finds further that the issue of what remedies may be available to the Companies should deferrals exceed borrowing limits is not yet ripe for decision. No party presented evidence that such a scenario is likely, taking into consideration the Department's findings with respect to standard offer pricing. The claim amounts to little more than ungrounded speculation. Further, the Companies' schedules for transition cost recovery exclude the residual value credit and further mitigation before divestiture, both of which would tend to decrease the level of the access charge, reducing the possibility of exceeding 1
the Companies' borrowing limits during the transition period. The Department avoids, where possible, rendering advisory decisions on matters that have not matured into an actual controversy for resolution through the adjudicatory process. If and when a fact-based controversy arises, the Department will consider it in due course.
- 3. Unbundled Distribution Rates
- a. The Plan Cambridge and Commonwealth propose to base their unbundled distribution rates on updated COSS that use calendar year 1995 adjusted costs (Exh. CEC-1, Tab D at 13,17).
Therefore, the results of these 1995 COSS affect the total distribution revenues Cambridge and Commonwealth will collect from their distribution rates.
- b. Positions of the Parties _
The Attomey General states: "[gliven the limited time frame for this case and the scope of the issues, a rate case type of analysis was not performed" (Attorney General Brief at 35). However,-the Attorney General accepts the calculations of the unbundled rates for the limited purposes of establishing the level of costs necessary to open access and I ( l
D.P.UJD.T.E. 97 1I1 Page 39
. provide for the divestiture of the generation function (Attorney General Brief at 35). SORE, on the other hand, asserts that both Cambridge and Commonwealth have received excessive camings during 1995 and, therefore, should file a more up-to-date COSS (SORE Brief at 5).
The Companies state that they have not received excessive earnings during 1995 (Companies Brief at 48). Also, the Companies state that the Act is silent on the issue of revenue requirements and COSS in relation to restructuring filings and that a general rate case is beyond the scope of this proceeding (it). l
- c. Am1vsis and Findines '
Cambridge and Commonwealth determined their distribution rates based on updated i COSS. The cost of service analyses used the method that the Department has approved for J developing base rates. Sgg Massachusetts Electric ComnaDY, D.P.U. 95-40 (1995); (.' Cambridae Electric Linht Comoany, D.P.U. 92-250 (1993); Commonwealth Electric Comoany, D.P.U. 90-331(1991). The Department traditionally has reviewed proposed changes to base rates by conducting a thorough review of the costs included in the COSS and j the manner in which the costs were functionalized and allocated. A cost of service investigation typically takes six months to complete. In this proceeding, the COSS is used only to develop the distribution costs, whereas, l in a base rate proceeding the COSS is used to develop the customer, distribution, transmission, and generation costs. Consequently, the COSS in this proceeding has less of an impact on the total costs collected by the Companies than the COSS filed in a base rate proceeding has on total costs collected. Therefore, given the limited time to implement retail choice, the scope of this proceeding, the limited effect of the COSS on Cambridge's and
e,'. , e' e*
- D.P.UJD.T.E. 97-111 Page 40 L Commonwealth's total costs, and the fact that the proposed rates are unbundled and provide a 10 percent discount as required by the Act, the Department finds Cambridge's and Commonwealth's proposed distribution costs to be appropriate for the purposes of this proceeding. However, the Department, in a future rate proceeding, will conduct a thorough wview of the costs included in the distribution rates" and the manner in which the costs included in the COSS were functionalized and allocated. "
- 4. Bundled Charges Cambridge and Commonwealth propose to bundle the distribution, DSM, renewables, and transition charges in the rate tariffs. The Act states that all electric bills sent to retail customers shall be unbundled to reflect separately the rates charged for generation, transmission, and distribution services, as well as any other charges, as added pursuant to any provision of law, contained in the total retail price. Any transition charge, if approved, shall be reflected separately on bills as of March 1,1998. St.1997, c.164, i 193 (G.L. c.
164, i 1D). Since the Act requires the distribution, DSM, renewables, and transition charges to be itemized separately on the bill, the Depanment directs Cambridge and Cornmonwealth to unbundle these charges in the tariffs. The Act gives the Department the authority to establish performance based rates. St.1997, c.164, f 193 (G.L. c.164, f IE). The Department must determine the appropriate " cast-off" rates before establishing performance-based rates. Ess, Boston Gas Comnany, D.P.U. 96-50 at 346 347 (1996). A thorough review of the COSS will be necessary to establish the appropriate " cast-off" rates. The Department plans to conduct a generic proceeding on performance quality standards. After the conclusion of the performance quality standards proceeding, the Department plans to investigate each distribution company's distribution rates when [- appropriate and then establish performance-based rates.
4 - .,* D.P.U/D.T.E. 97-111 Page 41 The Department notes that the DSM-related provisions of the Act, as found in G.L. c. 25, i 19, pertain to utility-sponsored programs. In contrast, funding for the senewable energy projects authorized by G.L. c. 25, i 20 is administered by the Massachusetts Technology Park Corporation. To ensure that DSM and renewables funds are properly tracked, the Department finds it appropriate to require that they be separately l tarified." St.1997, c.164, f 37 (G.L. c. 25, i 20(c)). Additionally, separate tariffs for ' DSM and renewables would further the intent of the Act that DSM and renewables charges l are to be identified separately on customers' bills.20 St.1997, c.164, f 37 (G.L. c. 25, 6 20(a)(1)). Therefore, the Company is hereby directed to file separate DSM and renewables tariffs. ,
- 5. Nenative Charnes On Tariffs '
Cambridge proposes a negative off-peak KWH distribution charge for rates R-5 and R-6 (Exh. CEC-1, Exh 1.B at 5, 6), if the transition charge remains bundled with the distribution charge, the total bundled charge is positive. Therefore, Cambridge maintains there is no problem with this proposal (Tr. 3, at 141). However, in Section IV.B.4, above, the Department has directed Cambridge to unbundle the transition and distribution charges. Cambridge can eliminate the negative distribution charges by redesigning the R-5 and R-6 i Consistent with this finding, Cambridge and Commonwealth are directed to modify their retail delivery tariffs to include a rate adjustment clause to specify the separate i adjustment components for the DSM charges and renewables charges. l !- 2' ! The Department has directed the distribution companies, through meetings with our l l consumer division, to itemize these charges separately on customers' bills. The i Department understands that such itemization may be delayed , but no longer than three months, while Cambridge and Commonwealth reprogram their computer systems ( to accommodate these additional changes. l ! 1 I
j l l D.P.U/D.T.E. 97-111 - Page 42 rates as follows: change the transition charge from being the same charge for the on-peak l and off-peak periods to a charge that is higher for the on-peak period than it is for the off-peak period, but that overall collects that same amount of revenue as having a uniform 1 charge l (RR- DTE-33). Accordingly, the Department directs the Company to redesign the R-5 and R.4 rates to remove the negative distribution charges.
- 6. Streetlight Rates
- a. The Plan Cambridge and Commonwealth propose streetlight rates that include an annual luminaire charge that bundles the distribution, transition, and, if applicable, fixture and maintenance costs (Exh. CEC-1, Exh. I.B at 15-27, and Exh. II.B at 18-46). Both Cambridge and Commonwealth state the transmission charge separately on the streetlight tariffs.
- b. Positions of the Panies
- i. .'Q3_fompact The Compact states that municipalities (1) have the right to purchase the streetlight equipment previously owned by the distribution company; (2) can obtain generation service from a competitive supplier, regardless of whether the distribution company or the municipality owns the lighting equipment; and (3) can convert electric service to an l altemative tariff that provides rates for distribution-only service (Compact Brief at 36, niing i
St.1997, c.164, i 1% (G.L. c.164, i 34A)). The Compact contends that the Companies' ! Plan is silent on how they intend to comply with the streetlight provisions in the Act. Lastly,
.(
l - - - . . - -- - - - _ - , . _ . . - _ - - - .
.' i .*
D.P.U/D.T.E. 97-111 Page 43 l l the Compact points out that the Companies did not propose an alternative tariff for l l municipalities that acquire the. Companies' streetlight fixtwes and, therefore, wish to receive distribution-only service (ii). Accordingly, the Compact states that the Companies should be directed to implement the provisions of Section 196 of the Act and propose an alternative tariff with that provision in mind (it at 37). ii. The Companies The Companies state that the Act does not require any municipal streetlight proposal to be filed with the Plan (Companies Brief at 46). Instead, according to the Companies, the Act presumes that distribution companies and any interested municipality will negotiate the purchase of streetlight equipment and related matters as set fonh in the Act (ii). The Companies maintain that such negotiations will likely occur on a case-by-case basis and do (. not require any specific subrnittal as pan of this case (ii). The Companies maintain that they are willing to negotiate potential streetlight acquisitions with any interested municipality and, consequently, the Compact's request for more specific information as pan of the Plan should be rejected (ii).
. c. Analysis and Findines With respect to the Compact's argument that more specific information is needed as part of the Plan, the Depanment agrees with the Companies that the Act does not require the filing of any municipal streetlight proposal with the Plan. If a municipality is interested in taking actions allowed by Section 196 of the Act, the Companies' Plan does not prohibit such i
l actions. However, tM Act requires bills to be unbundled to separately reflect the rates l
- charged for generation, transmission, transition, and distribution services, as well as any f
i
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)
- D.P.U/D.T.E. 97-111 Page 44 l -
j other charges, as added pursuant to any provision oflaw. St.1997, c.164, i 193 (G.L. c. l 164, I ID). Therefore, the Department directs Cambridge and Commonwealth to separate the DSM charge, renewables charge, and transition charge from the luminaire charge on the streetlight tariffs.2" With respect to the language on the proposed streetlight tariffs, Cambridge and Commonwealth did not state that customers on the streetlight rates are subject to the DSM charge, renewables charge, transition cost adjustment and the transmission cost adjustment. Also, Cambridge and Commonwealth did not state that standard offer service and default I service are available to customers on the streetlight rates. The Department directs Cambridge and Commonwealth to disclose on the streetlight tariffs that customers are subject to the DSM charge, renewables charge, and transition cost adjustment and to state the (. availability of standard offer service and default service on the streetlight tariffs.
- 7. Tariff Provisions ;
Section 315 of the Act requires distribution companies to offer a 10 percent discount to customers engaged in the business of agriculture or farming. Cambridge and l Commonwealth did not include this d' iscount in the Plan. However, during the proceedings,
. Cambridge and Commonwealth indicated that they would include appropriate language in I their compliance filings (Exh. DTE-37). Accordingly, the Department directs Cambridge and Commonwealth to revise their retail tariffs by including the farm discount.
j 2' The rate reductions required by the Act should be reflected in the streetlight tariffs. ! However, municipalities that choose, pursuant to Section 196 of the Act, to purchase ( streetlights and then convert to an alternative tariff may fall outside the rate reduction requirements of the Act.
( .; l - l D.P.U1D.T.E. 97-111 Page 45 Cambridge's and Commonwealth's residential tariffs state that a customer must give a minimum of four days' notice to terminate service. The Department's Model Tenns and Conditions for Distribution Service, D.P.U./D.T.E. 97-65 at Section II.6C, state that a customer must give at least three business days' notice to terminate service. Accordingly, Cambridge and Commonwealth are directed to revise their residential tariffs to comply with , Section II.6C of the Model Terms and Conditions for Distribution Service. With respect to Cambridge's and Commonwealth's proposal to cancel the fuel charge, conservation charge and energy comervation service charge on March 1,1998, the Depanment finds the following. In D.T.E. 98-13 we stated: "[t]he Department finds that the opening of the Massachusetts market to competition staning March 1,1998 negates the need for the fuel charge requirements of G.L. c.164, (( 94G and 94G1/2." Id. at 4. Therefore, the Depanment finds it appropriate to tenninate the fuel charge tariff for consumption on or after March 1,1998. In addition, the Act replaces the conservation charge and energy conservation service charge with the DSM charge. Accordingly, it is appropriate for Cambridge and Commonwealth to terminate their conservation charge and energy conservation service charge for consumption on or after March 1,1998. Lastly, the Department makes no findings in this proceeding with respect to Cambridge's and Commonwealth's proposed terms and conditions tariffs, default service tariff, and standard offer tariff. Instead, the Department defers its review of these tariffs to the Model Tenns and Conditions proceeding, D.P.U/D.T.E. 97-65. i l
l , .,,- , D.P.U/D.T.E. 97-111 Page 46
- 8. Notifiention Period for Self-Generation
- a. Introduction The Act states that utility companies and the Department shall not require a customer to give more than six-months' notice of plans to install on-site generation or cogeneration l facilities. St.1997, c.164, i 193 (G.L. c.164, { IG). Cambridge and Commonwealth filed proposed tariffs for general service that include a two-year notification period for I
customers who are planning to self-generate (Exh. CEC-1, Tab E; Exh. CEC-1, Tab F).
- b. Positions of the Panies
- i. The Comoact The Compact states that there is a discrepancy between the Act and the Coinpanies' filing (Compact Brief at 33. siling Tr. 5, at 34-37). The Compact argues that the proposed i two-year notification period erects unreasonable and unauthorized barriers to on-site generation (i1 at 33-34). 1 ii. The Comoanies The Companies acknowledge the discrepancy between their original filing and the Act regarding the notification period for self-generation contained within their general service l
tariffs (Companies Brief at 56-57). The Companies indicate that they will revise the filing so that the notification period for self-generation is reduced to six months for general sen' ice tariffs (ii).
\
1
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l l D.P.U/D.T.E. 97-111 Page 47 k c. Analysis and Findines The Department notes that Cambridge and Commonwealth have already agreed to revise their tariffs in order to comply with the Act. Nevertheless, the Department directs Cambridge and Commonwealth to revise their general service tariffs by reducing the notification period for self-generation from two years to six months. In addition, in order to comply with the Department's rules, net metering customers shall be exempt from this i notification requirement. 220 C.M.R. I 11.04(7)(c).
- 9. Commonwealth's Notification Period for Termination of G-2 and G-3 Service
- a. Introduction Commonwealth filed proposed Medium General Time-of-Use ("G-2") and large
[ General Time-of-Use ("G-3") tariffs that required customers to provide a 24-month written notice before service would be terminated by Commonwealth (Exh. CEC-1, Tab F, Proposed , i M.D.P.U No. 345, at 4; Exh. CEC-1, Tab F, Proposed M.D.P.U. No. 346, at 4). ! Cambridge filed proposed G-2 and G-3 tariffs that require a six-month written notification l period for termination of service (Exh. CEC-1, Tab E, Proposed M.D.P.U. No. 595, at 4; 4 l Exh. CEC-1, Tab E. Proposed M.D.P.U. No. 596, at 3).22 2: The same written notification provisions are in place on Cambridge's and Commonwealth's current tariffs. Cambridge's current G-2 and G-3 tariffs (M.D.P.U. 535B and M.D.P.U. 536B, respectively) have an effective date of June 1,1993. g Commonwealth's current G-2 and G-3 tariffs (M.D.P.U. 295 and M.D.P.U. 296, respectively) have an effective date of May 1,1995. '
. -. ._ _- _._ - _. . - - = . . - - .
j D.P.UJD.T.E. 97-111 Page 48 i l- b. Positions of the Parties SORE states that there is a difference in the notification provision between Cambridge and Commonwealth (SORE Brief at 11). SORE maintains that there is no explanation in the Companies' petition for the different notification provisions contained in Cambridge's and Commonwealth's general service tariffs (ii). SORE argues that if the six-month term contained in Cambridge's G-2 and G-3 tariffs is acceptable to the Department, then the same notification period should be applied to Commonwealth's G-2 and G-3 tariffs (iLL The Companies did not address this issue on brief.
- c. Analysis and Findings The Act requires a six-month notification period for customers who choose to self-generate.23 In the event tlat a Commonwealth customer being served under the G-2 or G 3 tariff decides to self-generate, this customer could be obligated to pay the minimum monthly charges under the G-2 or G-3 tariff for up to 18 months after it commences self-generation.
The Department finds that the discrepancy in Commonwealth's G-2 and G-3 tariffs between the notification period for self-generation and the notification period for termination of service is without justification and is, therefore, unreasonable. Accordingly, the Department i directs Commonwealth to revise its G-2, Medium Generalinnc-of-Use tariff, and its G-3, j Large General Time-of-Use tariff, by reducing the written notification period for termination of service from 24 months to six months. l 23 Customers who are eligible for net mw arvice are exempt from this notification f requirement. .
. ' L, . '
e ,. D.P.UJD.T.E. 97-111 Page 49 l C. Special Rates l
- 1. IAw-Income Tariffs The Act sets fonh the low-income eligibility requirements to be used by all i
distribution companies in the Commonwealth. St.1997 c.164, i 193 (G.L. c.164, 6 IF(4)(i)). In accordance with the Act Cambridge and Commonwealth are directed to modify their low-income tariffs by replacing the eligibility criteria with the following language: Electric delivery service under this rate is available upon verification of a customer's eligibility for the low-income home energy assistance program, or its successor program, or verification of a customer's receipt of any means tested public benefit, for which eligibility does not exceed 175 percent of the federal poveny level based on a household's gross income, or other criteria approved by the Depanment. In addition, the Act requires all distribution companies to guarantee payment to competitive suppliers for all power sold pursuant to the low-income tariffs. St.1997 c.164, [ i 193 (G.L. c.164, i 1F(4)(i)). Therefore, the Depanment directs Cambridge and Commonwealth to add the following language to their low-income tariffs: The Company will guarantee the customer's payment to its designated supplier up to the prices that the Company charges to customers for standard service. With respect to outreach, the LII state that the Companies have not included a substantial outreach proposal as a pan of their Plan and claim that an outreach proposal is needed because Cambridge's and Commonwealth's outreach efforts need much improvement (LII Brief at 1-2). The Companies maintain that the LII's criticisms of their outreach effons , l are without foundation (Companies Reply Brief at 51). i
l l I D.P.U/D.T.E. 97-111 Page 50 I The Depanment finds that although the Act requires distribution companies to pursue efforts to make the low-income discount available to eligible customers, the Act directs DOER to monitor such activities and requires each distribution company to report annually to DOER. While there is nothing in the Plan that describes the Companies' outreach efforts, the Depanment expects the Companies to make such efforts and to file reports with DOER, in accordance with the Act. Therefore, the Plan substantially complies with the Act. Eng D.P.U./D.T.E. 96-23, at 67 (1998).
- 2. Termination of Discount Tariffs
- a. Introduction The Act states that the 10 percent rate reduction shall be applied against undiscounted rates in effect during August 1997 or such other date as the Depanment may determine to be representative of 1997 rates.' St.1997, c.164, { 193 (G.L. c.164, i 1A).
Commonwealth proposes to eliminate its discount tariffs, which include the large General Economic Development Rider, large General Economic Development Rate (Closed), Service Extension Discount Rider, Vacant Space Rider and Retail Choice Pilot Program (" Economic Development Tariffs"), as of March 1,1998 (Exh. CEC-1, Tab D at 16). Customers currently receiving service under these discounted tariffs will receive a 10 , percent rate reduction based on Commonwealth's current G-2 or G-3 rates (it at 17). l Cambridge does not currently have any discount tariffs in place (AG-RR-14). l i
. . - . .w . -.-,r
/ .'
i D.P.U/D.T.E. 97-111 Page 51 l l C b. Positions of the Parties l l . i. Acushnet Rubber Conioany. Inc. I Acushnet states that Commonwealth's economic development rates were formulated to help New Bedford industrial manufacturers compete (Acushnet Comments at 1). Acushnet , l claims that Commonwealth's use of the G-3 tariff as the baseline for calculating the 10 percent rate reduction will result in rate increases for customers currently on economic development rates (it). In addition, Acushnet asserts that the impact of this rate increase will be to diminish New Bedford's industrial customers' ability to secure business and retain jobs (ii). ii. SORE SORE argues that Commonwealth is using an inflated baseline for calculating the 10 (~ percent rate reduction (SORE Brief at 3). As a result, SORE claims that many of its members will not realize a 10 percent reduction from their August 1997 rates and will, therefore, experience an economic disadvantage relative to other Massachusetts industrial customers (ii). SORE objects to Commonwealth's proposal to eliminate the discounted tariffs and urges the Department to consider the merits of each tariff and the impact on companies now taking service under these rates (ii). In addition, SORE recommends that Commonwealth and the Department consider using a discounted baseline or a hybrid baseline beginning March 1,1998 to calculate the 10 percent rate reduction in order to help mitigate additional economic disadvantage to New Bedford area industrial customers (it at 4). SORE also argues that the Retail Choice Pi'ot Program tariff is not a discour.ted rate (ii). (
. l V .*
D.P.U/D.T.E. 97-111 Page 52 lii. The Comoanies The Companies maintain that since the Act provides for a 10 percent rate reduction from undiscounted rates, the Legislature did not intend to institutionalize price discounts as part of the development of the 10 percent rate reduction (Companies Reply Brief at 47). Because the Economic Development Tariffs are discounted rates, the Companies recommend that the Depanment reject SORE's request that the Department use a discount or hybrid baseline rate for industrial customers in the Companies' service territories against which the 10 percent rate reduction mandated by the Act would apply. The Companies state that SORE's proprosed modification would be inconsistent with the Act's requirement of a 10 percent rate reduction from undiscounted rates (it). In addition, the Companies state that the fundamental premise of the Act is to allow each class of customer the opponunity to , I ( ' bargain with electricity providers to receive the lowest possible rate for electricity (11). l
- c. Analysis and Findines !
l The Act states that utilities must provide a 10 percent discount from "undiscounted" rates that were in effect in August 1997, or some other period that the Depanment detennines to be representative of 1997 rates. Commonwealth's current Economic Development Tariffs are non-cost-based rates since they are discounts from cost-based tariffs. Commonwealth's current Economic Development Tariffs are also not subject to deferred l recovery. For these reasons, the Depanment finds that Commonwealth's current Economic Development Tariffs are discounted rates. Accordingly, the Depanment finds funher that Commonwealth has properly used the G-2 and G-3 tariffs as the baseline for the calculation
- of the 10 percent rate reduction for customers currently served under the Economic
(- l N
e .. D.P.U/D.T.E. 97-111 Page 53 L Development Tariffs. The Department is aware that parts of Commonwealth's service tenitory would benefk from the economic stimulus of lower electric rates and that discounted tariffs and special contracts may help keep cenain business operations viable. One of the primary objectives of offering retail choice to electricity consumers of Massachusetts is to give them more options for wing their energy needs. Retail choice will provide consumers with the i opponunity to choose to purchased power from a competitive supplier or remain with their incumbent electric utility through standard offer service. The Depanment encourages the Companies to pursue all necessary solutions to meet the energy needs of their customers. I The Depanment has been supponive of electric company Economic Development Tariffs in the past and believes that properly designed ecortomic development rates can be provided to ( customers by distribution companies in the future.2' Commonwealth Electric Comoany, l D.P.U. 93-41, at 20 (1993).
- 3. Interruptible Rates Cambridge and Commonwealth proposed to discontinue intenuptible service tariffs (Exh. CEC-1, at 16,18). According to the Attorney General, the intenuptible rates are cost-based and do not represent a discount as such, but rather compensation for avoided marginal capacity and transmission costs (Attomey General Brief at 31, siting Commnnwealth Electric Comoany, D.P.U. 89-114/90-331/91-80, at 308 (1991); Cambridce 1 Electric Linht Comoany, D.P.U. 89-109, at 111 (1989); Commonwealth Electric Comoany, The Department has stated that a discount to one customer is not recoverable from
{ remaining ratepayers. Massachusetts Electric Comoany, D.P.U. 95-40, at 142-143 (1995).
D'.P.U/D.T.E. 97111 Page 54 D.P.U. 88-135/151, at 226- 227 (1989)). Therefore, the Attorney General states that Cambridge and Commonwealth should continue their interruptible rates for those ct stomers who remain on standard offer service, since the benefit of having internsptible load weuld flow to the entity that serves the load (11 at 31-32). The Companies state that they have reviewed their policy and have determined that other distribution companies such as Massachusetts Electric Company are continuing the interruptible service tariffs (Companies Brief at 51). Accordingly, like Massachusetts Electric Company, Cambridge and Commoriwealth popose to revise their Plan to offer existing interruptible credits through the year 2000 to any customer currently receiving credits s's long as the customer continues to take standard offer service (ii). Since the interruptible credits are cost-based and Cambridge and Commonwealth agree to continue ( them, the Department directs Cambridge and Commonwealth to revise their Plan to offer existing intermptible credits through the year 2000 to any customer currently receiving credits as long as the customer continues to take standard offer service. D. Transition Costs
- 1. Introduction The Act defines four principal types of transition costs: (1) the depreciated book value of owned generating plant that cannot be recovered at market prices; (2) the amount by which obligations under power purchase agreements ("PPAs") exceed the amount the same energy and capacity could be bought or sold for in the competitive market ("above-market"
(
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D.P.UJD.T.E. 97-111 Pag ~e 55 ( j
)
PPA costs), including buyout and buydown payments s for liquidating above-market PPAs; ; l (3) the as-yet unamortized generation-related Department approved regulatory assets; and j (4) post-shutdown nuclear costs. St.1997, c.164, i 193 (G.L. c.164, i 1G(b)(1)). The Act allows three other types of transition co s: (1) employee-related transition costs such as severance pay and employee retraining; (2) property taxes or payments in lieu of property taxes; and (3) removal and decommissioning costs for certain fossil-fueled generation. L (G.L. c.164, i 1G(b)(2)). The Act recognizes several types of mitigation to reduce transition costs and overall rates: (1) sale of generating plant; (2) renegotiation of PPAs to decrease the buyer's obligations; (3) netting above-market generating assets against below-market ones; (4) analysis of PPA performance; and (5) any other reasonable and effective mitigation mechanisms. R (G.L. c.164, f 1G(d)(1)). (' According to the Plan, the present value of Commonwealth's estimated transition costs amounts to $940 million in the base case, in which no mitigation occurs 26 (Exh. CEC-1, Exh. IV, Sch.1, at 1, 9). The corresponding amount for Cambridge is $150 i million in the base case t
' (ii, Exh. III, Sch.1, at 1, 9)
- 2. Catenories and Amounts of Transition Costs l
- a. Overview of the Plan The Plan's estimated transition costs include both fixed and variable costs (ii, Exh.111 at 1-13, Exh. IV at 1-15). In the base case, fixed costs represent almost nine percent of 25 Such payments can also be viewed as mitigation of transition costs, when considered together with reductions in minimum payments under PPAs.
2* The calculation uses Ccmmonwealth's proposed discount rate of 13.51 percent. f
! 2' The calculation uses Cambridge's proposed discount rate of 12.69 percent.
{,'*..' - D.P.U/D.T.E. 97 111 Page 56 Commonwealth's es'timated transition costs and 11 percent of Cambridge's estimated i transition costs (ii, Exh. III, Sch.1, at 1, Exh. IV, Sch.1, at 1). The book value of I generating plant is $33 million for Commonwealth and $16.5 million for Cambridge (ii, ! l l Exh. III, Sch.1, at 5, Exh. IV, Sch.1, at 5). The remaining fixed transition costs are regalatory assets, including $50 million for Commonweahh and negative 50.3 million for Cambridge (ii, Exh. III, Sch.1, at 6, Exh. IV, Sch.1, at 6). j Estimated above-market costs of PPAs under which Commonwealth buys power account for 89 percent ofits estimated variable transition costs in the base case, or about , j 81 percent of its total transition costs (ii, Exh. IV, Sch.1, at 1,3). The corresponding PPA l numbers for Cambridge are 62 percent of variable transition costs and 55 percent of total transition costs (11, Exh. Ill, Sch.1, at 1,3). For Commonwealth, the remainder of the l (. variable transition costs is divided almost evenly between estimated nuclear decommissioning costs and transmission in support of remote generation (with each being 4 to 5 percent of total transition costs), with a very small amount for above-market fuel transportation (ii, Exh. IV, Sch.1, at 3). For Cambridge, estimated decommissioning costs account for 61 percent of a remaining variable transition costs, or 28 percent of total transition costs; most of the remainder (about 5 percent of total transition costs) is for transmission in support of remote j l generation, again with a very small amount for above-market fuel transportation (ii, Exh. III, i Sch.1, at 3). The dollar amounts of four types of transition costs are yet to be determined: PPA buyouts, payments in lieu of property taxes, employee severance and retraining, and damage claims (11, Exh. III, Sch.1, at 3, Exh. IV, Sch.1, at 3). t l The Companies propose to collect their transition costs in an access charge over 12 \
( e d
]
l D.P.U/D.T.E. 97-111 Page 57 i k- years for fixed charges and over the lives of the obligations for the variable charges (it, Exh. III, Sch.1, at 1-3, Exh. IV, Sch.1, at 1-3). For Conanonwealth, the Plan caps the I access charge at 4.26 cents per KWH for three years, after which it falls to 3.74 cents (11, l Exh. IV, Sch.1, at 1).28 In the base case (11, before mitigation), the access charge falls slowly from 3.74 cents in 2001 to 1.12 cents in 2016 and vanishes in 2027 (16, Exh. IV, i i Sch.1, at 1). For Cambridge, the access charge is set at 2.73 cents in 1998 and 1.88 cents l in 1999, falls in the base case to 1.43 cents in 2007 and 0.45 cents in 2009, and vanishes in ; 1 2027 (11, Exh. III, Sch.1, at 1). i
- b. Positions of the Parties
- i. The Attorney General l The Attorney General contends that the Companies have improperly included in the
(. - access charge several costs pertaining to generating facilities and regulatory assets (Attorney General Brief at 11-24). In addition, the Attorney General contends that the Companies are ; proposing a different carrying charge for certain regulatory assets in this case than was allowed by the Department when those regulatory assets were created (it at 17-18, 24). The Attorney General argues that the Companies have improperly treated five costs for generating units (11 at 12-16). First, he claims, the Companies should treat their entitlements in nuclear units as ownership interests rather than PPAs, since other companies with approved restructuring plans did so (it at 12). He argues that the Companies should 2: To maintain the access charge at the cap for 1998-2000, Commonwealth accelerates amortization of fixed transition costs initially (Exh. CEC-1, Exh.1, Sch.1, at 2). During 2001-2009, fixed transition costs are amortized in equal amounts, resulting in a f declining return of fixed assets and most of the decline in the overall access charge I (ii). h .
l i D.P.U/D.T.E. 97-111 Page 58 recover only net, prudent costs committed as of December 31,1995, with carrying costs at the mitigation incentive rate, and 80 percent of the "to go" results"(i1 at 12-13). Second,
. the Attorney General maintains that the retail companies should be denied recovery of prepayments for operations and maintenance ("O&M") expenses at Seabrook 1, since these short-term costs should be collected through an adjustment to working capital (it at 13-14).
Third, the Attorney General contends that the current balances of nuclear cott costs should not be recovered at this time, since they are not stranded until a reactor is retired and may be fully mitigated by salvage value in any event (it at 14). Fourth, he argues that capital additions after 1995 should not be included in transition costs until the Companies have demonstrated directly and individually that they were actually committed before 1996 (it at 15). Fifth, he urges that the Department credit all sales of Company property since the (, , last base rate case as mitigation to reduce the initial balance of stranded generation plant investment included in the transition charge calculation (it at 15-16). The Attorney General claims that Oc Companies have inappropriately treated various regulatory assets in eight ways (it at 16-24). First, he contends that Commonwealth has miscalculated the current balance connected with the litigation of past outage costs for the ' Pilgrim nuclear power plant (" Pilgrim") and is claiming a rate of return on this regulatory asset higher than that allowed in the Department's Order creating it (it at 16-18). Second, he argues that Commonwealth similarly claims a rate of return on the Pepperell and Tenaska PPA buyouts higher than that allowed in the Department's authorizing Order (it at 18).
" The "to go" results are the income from selling the plant's output, less the plant's
( \ variable costs.
e '.. , l l D.P.U/D.T.E. 97-111 Page 59 Third, be maintains that Commonwealth proposes to charge ratepayers twice for the abandoned Cannon Street plant, by claiming as a regulator / asset money that has been { collected in base rates as depreciation expense since 1991 (it at 19-20). Fourth, he claims i that the modest asbestos removal costs at Cannon Street which were incurred several years ago should not now be included as regulatory assets, because (1) they should have been expensed in the first place; (2) retroactive ratem*ing should not be allowed; and 1 (3) Commonwealth's earnings were more than adequate to cover this pre-test-year expense, when test year rates were adequate to absorb such expenses (i1 at 20-22). Fifth, he claims there are problems with the treatment of debt issuance expenses (it at 22). (These issues are discussed in greater depth in Section VI.D.9.) Sixth, he argues that the ratemaking treatment of deferred fuel costs should be determined in the Depanment's generic docket on the subject, instead of immediately treating these costs as a regulatory asset (it at 22-23). Seventh, he contends that the final balances for DSM activities should be trued up through the established DSM mechanisms, with their specific carrying charge rate, rather than treated as a regulatory asset and recovered through the transition charge (i1 at 23). Eighth, he claims that the carrying charges on pensions and post-retirement benefit costs other than pensions ("PBOPs") should be the actuarially determined rate rather than the rate proposed by the Companies (it at 24). ii. The Comoanies The Companies address the Attorney General's claims in turn (Companies Reply Brief at 29-39). For generation costs, the Companies first state that the nuclear entitlements are FERC-approved contracts, arguing that treating the entitlements as ownership would change
1 . .. j l D.P.U/D.T.E. 97-111 Page 60 ' l l the timing but not the amounts recovered, and claiming that nothing in the Act requires shating of to go" results between shareholders and ratepayers & at 29 30). Second, the Companies contend that disallowance of prepaid O&M expenses would be disallowance of pmdently incurred costs under a FERC-approved contract (iL at 31). Third, the Companies maintain that nuclear fuel cores are on Canal's books and that any future salvage value can be reflected in future mitigation reconciliations (hL at 32). Fourth, the Companies argue that they presented substantial evidence supporting capital additions made after 1995 and that these costs will be subject to later audit and reconciliation & at 32-33). Fifth, they claim to agree with the Attorney General and state that sales of surplus transmission and distribution land will be reflected as mitigation in future proceedings & at 33).
. Regarding regulatory assets, the Companies first address the Pilgrim litigation costs, i
contending that the dollar difference in question is an appropriate update to an earlier ; estimate and that it is appropriate to apply the transition cost carrying charge to all regulatory assets, including Pilgrim litigation costs (it at 33-34). Second, the Companies argue likewise that the transition cost carrying charge should apply to all regulatory assets, including the Tenaska and Pepperell PPA buyouts (it at 34). Third, the Companies maintain that Cannon Street depreciation was discontinued, the reference to inclusion in base rates since 1991 is misleading, and the Attorney General's proposed treatment of Cannon 1 i u Street would require corresponding additions to rate base of many other expenses (it at 35). Fourth, the Companies claim that the Cannon Street asbestos removal cost was approved by FERC after a thorough review and without objection by the Department (it at 36). Fifth, the Companies' response to the Attorney General's proposed treatment of debt issuance costs
,. i
.c .. .
D.P.UJD.T.E. 97-111 Page 61 is discussed in Section VI.D.9., below. Sixth, the Companies contend that the fuel cost adjustment amount is large and must be spread over several years to avoid increasing rates when they are supposed to decrease, a result that will be achieved by treating them as a transition cost but may not be achieved in the Depanment's generic docket on the subject (it at 37). Seventh, the Companies maintain that it is best to treat the DSM balance as a regulatory asset because the conservation charge ends on the retail access date (it at 38). Eighth, the Companies argue again that the carrying charge on regulatory assets should be a i single rate once accounts are moved from rate-case recovery to transition-cost recovery, 1 l including in this case pensions and PBOPs (ji at 38-39).
- c. Analysis and Findmus i The Act specifies the types of transition costs that a company may recover in an I access charge. St.1997, c.164, i 193 (G.L. c.164, i 1G(b)). Based on its review, the Department finds that in general the types of transition costs claimed by the Companies are I those types for which the law allows recovery. The verification of the exact amounts awaits a more comprehensive audit, which the Depanment must complete for the Companies by March 1, 2000.11, (G.L. c.164, il I A(a),1G(a)(1)).
However, the Attorney General has raised many issues about appropriate treatment of panicular items that the Companies have proposed for inclusion as transition costs, with the same carrying charge rate for them all, which in some cases would alter the carrying charge i j rates allowed by the Department in previous orders. Full audit and investigation of these issues by the Depanment would require more time than is available before the Department a
- must issue an order allowing retail access to begin for the Companies' customers. The i (
4 e d 1
4 , . l D.P.U/D.T.E. 97-111 Page 62 amounts involved are all subject to audit and reconciliation. Accordingly, the Depanment will defer making findings at this time and determine the appropriate treatment of these proposed transition costs in the first case aconciling actual transition costs to estimated transition costs. In the meantime, the Depanment will allow the Con:panies to charge these contested amounts provisionally as transition costs, subject to stfund with interest at the Cam,= abs' proposed transition carrying charge rates or such other rates as the Depanment may determine in that proceeding.
- 3. Mitiention
- a. Overview of the Plan The Plan states that the Companies have offered their generating plants for sale and !
that bidding is currently under way (Exh. CEC-1, at 5, 21-23).38 The Companies add that ; first-round bids were received in December 1997 and a short list of bidders are currently engaged in due diligence efforts before their expected submission of final, binding bids in ! March 1998 (Exh. ECT-10). The Companies state that the proceeds of the sale will be used to reduce, or mitigate, the amount of transition costs and in turn reduce the access charge, via a residual value credit'2 (Exh. CEC-1, Exh. III, Sch.1, at 2, Exh. IV, Sch.1, at 2; The Department will also require any refunds due to customers as a result of findings in the Companies' generating unit performance review cases to flow through the transition charge mechanism, since they would stem from the operation of generating plants, the source of transition costs. As discussed above, the Compai les plan to backstop their standard offer service obligations at pre-determined prices as part of their divestiture of generation resources (Exh. CEC-1, at 30).
" As discussed above in Section VI.A., the Companies propose that to the extent the access charges fall below their respective caps, standard offer charges may increase to cover any loss the Companies incur from selling standard offer power below the price
D.P.U/D.T.E. 97-111 Page 63 Companies Brief at 40). The Companies are also in the process of auctioning off the entitlements to electricity under their PPAs, offering several groups of PPAs, in the same general time frame as the divestiture auction (Exh. CEC-1, at 22-26; Companies Brief at 39-40). The Companies are requiring bidders to bid a fixed price stream that the Companies would pay (or receive from) winning bidders to take over the Companies' responsibilities under the PPA entitlements, thereby converting variable transition costs to fixed transition costs (isL). The Plan provides that PPA buyout expenses be entered into an annual reconciliation account that becomes active after 1998 for Cambridge and 2000 for Commonwealth (Exh. CEC-1, Exh. III, at 8, Exh. IV, at 9). Until the Department approves the results of the Companies' PPA auction, the PPAs' above-market costs will flow through the access charge to their customers, as ( adjusted by the reconciliation account (isL, Exh. III, Sch.1, at 1-3, Exh. IV, Sch.1, at 1-3). In addition, the Companies are selling their sulfur dioxide and nitrogen oxide allowances to mitigate transition costs (ist at 26). Moreover, to further reduce transition costs, the Companies are selling, leasing, or otherwise finding value froin real estate the 4 Companies no longer need, leasing space in the distribution network and on transmission and communications towers, and releasing right-of-way casements where they are no longer needed (ish at 27).
- b. Analysis and Findines The Act requires that companies take all reasonable steps to mitigate their transition costs and encourages them to divest their generating assets. St.1997, c.164, Q 193 l l
( at which they procure it (Exh. CEC-1, at 34). e
D.P.U/D.T.E. 97-111 Page 64 (G.L. c.164, If I A, IG). The Act further provides that the Department may allow a distribution company to recover its transition costs if it will divest its generating assets, mitigate its transition costs, and comply with the other imponant provisions of the Act. hL, (G.L. c.164, i 1G(b)(1)). Based on our review of the record in this case,'the Depanment fmds that the Companies have committed to full mitigation of their transition costs, principally by auctioning off their PPAs and generating plants. Therefore, the Plan complies with the Act on this point. After the Companies submit the results of their generation asset auctions for review, the Depanment will determine in a separate proceeding whether they have indeed maximized the level of mitigation as required by the Act. LL, (G.L. c.164, i 1G(d)(1)). Nevenheless, the Depanment finds that the Companies' proposal for the reconciliation ( , account requires a modification. Given the potential for large differences between estimated and actual transition costs due to variations in the market price for electricity and other factors, the Depanment directs Commonwealth to make its reconciliation account active on the same date the Plan proposes for Cambridge, January 1,1999. Finally, the Act requires a total rate reduction of 15 percent by September 1,1999. LL, (G.L. c.164, i IB(b)). Based on our review of the record in this case, the Depanment i fmds that the Companies' mitigation plan shows potential to achieve such a rate reduction by the required date, and therefore that the Plan substantially complies with the Act on this point. The Depanment will review the results of the Companies' mitigation effons to determine whether in fact they will result in the required rate reduction by the required date, or whether other measures specified in the Act will also be required. 1 (
l 1 ... l D.P.U/D.T.E. 97-111 Page 65 l C In light of the above considerations, and noting that the Companies' mitigation efforts ! l are already well under way, pursuant to St.1997, c.164, { 193 (G.L. c.164, i 1G(b)(1)), , , the Department hereby authorizes the Companies to collect an access charge for net, non- ; mitigable past investments that are classified as transition costs, subject to reconciliation,
]
based on the rates proposed in the Companies' Plan, as modified in accordance with the directives in this Order.
- 4. Deoreeintion Rate for Fixed Generation Assets
- a. The Comoanies' Proposal The Companies propose to depreciate the as-yet undepreciated cost of their fixed generating assets and regulatory assets over a 12-year period, ending in 2009 (Exh. CEC-1. Exh. III, Sch.1, at 2, Exh. IV, Sch.1, at 2). The Companies propose to
( accelerate the depreciation, relative to the straight-line depreciation method'8 historically employed for ratemaking purposes, for the first three years of the transition period for Commonwealth and for the first year for Cambridge (hL). The Companies propose to accelerate the depreciation in order to obtain a rate reduction, during the first year of the transition period, equal to the minimum 10 percent required by the Act (Exh. DTE-8). l Commonwealth proposes to continue accelerated depreciation for two more years, thus maintaining the access charge at its proposed cap, before switching to straight-line depreciation" (kL). Cambridge, on the other hand, proposed straight-line depreciation of the i 22 The Department has historically allowed companies to depreciate their fixed assets at a fixed rate, known as straight-line depreciation. ( " The Companies assert that they retain the flexibility to allocate the residual value credit differently, which affects the fixed access charge, if appropriate, to achieve
', o.,
D.P.U/D.T.E. 97-111 Page 66 _( remaining fixed transition costs after the first year, resulting in larger rate decreases after the first year (it; Exh. CEC-1, Exh. III, Sch.1, at 2),
- b. Am1vsis and Findines As stated above in Section VI.B.2., Commonwealth calculated its rate reduction by using a base " rate," including a particular fuel charge, that was never in effect. The Department has rejected this calculation and directed Commonwealth to use the fuel charge that was in effect for the entire year of 1997. Using the Department-ordered fuel charge rate results in the proposed depreciation schedule for fixed assets not yielding the 10 percent rate cut required by the Act. Accordingly, the Department directs Commonwealth to revise the initial depreciation of its fixed assets to provide a rate reduction of at least 10 percent.
When the Companies file their proposal to reduce the access charge pursuant to the ( results of their mitigation efforts, the Department directs the Companies to propose revised schedules for depreciation and/or the residual value credit that provide a stable and declining access charge.
- 5. Mitination Incentive
- a. The Comnanies' Proposal The Companies' proposed mitigation incentives are based on reducing the cumulative average access charge below their proposed access charge caps (Exh. CEC-1, Exh. III, Sch.1, at 4 Exh. IV, Sch.1, at 4). Commonwealth would receive an incentive for reducing the average access charge below 4.26 cents per KWH, while Cambridge would 1
receive an incentive for reducing the average access charge below 2.73 cents per KWH, ( stable and declining rates (Exh. DTE-1-41). l l
,'o '
i D.P.UJD.T.E. 97-111 Page 67 { calculated according to a table in the Plan (it). In the base case, in which no mitigation occurs, Commonwealth would receive $1.25 million in ine:ntives while Cambridge would receive $0.73 million (11). Commonwealth would receive the maximum incentive of million for reducing the cumulative average access charge to 3.06 cents per KWH, while ' Cambridge would receive the maximum incentive of $0.89 million for reducing the cumulative average access charge to 1.20 cents per KWH (ii). Neither company would receive any additional incentive for reducing the access charge further (iO.
- b. Positions of the Parties I Enron and the Compact contend that the Companies' proposed mitigation incentive is inconsistent with the Act (Enron Brief at 12; Compact Brief at 23-26). They argue that the Companies should not be allowed an incentive for taking actions required by the Act, namely
(.. mitigation of transition costs to the maximum extent possible (10. The Compact adds that 4 an incentive payment could violate the Act's requirement that all of the net proceeds from divestiture go to reduce the access charge (Compact Brief at 24-25)." Enron and the Compact observe that, under the proposal, the Companies could receive incentive payments for something that is beyond the Companies' influence, such as an increase in market prices above their forecast (it at 25; Enron Brief at 12). The Compact funher observes that Commonwealth will receive an incentive under its proposal simply for charging transition costs at the level currently forecasted (11 at 25). The Compact urges that any incentive mechanism approved by the Depanment reward the i - i " The Compact recognizes the Department's discretion to adjust the proceeds from { divestiture, to the extent such adjustments inure to the benefit of ratepayers (Compact Brief at 25, n.17, citing G.L. c.164, l A(b)(3)).
c .. i D.P.U/D.T.E. 97-111 Page 68 L. Companies only for exceptional results, such as mitigation above some floor level (it at 26). The Companies note that the stmeture of their proposed incentive mechanism is i almost identical to those approved by the Department as parts of settled restructuring plans (Companies Brief at 45). The Companies contend that their proposed incentive will motivate them to mitigate their transition costs aggressively to the fullest extent possible, which will inure to the benefit of ratepayers (it at 46). They add that the incentive mechanism provides the overwhelming majority of the mitigation benefits to ratepayers (ii). The Companies contend that the Department has used incentives in the past to motivate utility companies to act in the best interest of customers by aligning the financial interests of s shareholders and customers (ii, Eiling, Lt , Incentive Renulation for Electric and Gas Comoanies, D.P.U. 94-158, at 47-51, 53, 56 (1995)). ( c. Analysis and Findines i c , ! The Act provides that all proceeds from divestiture, less any adjustments approved by the Department that inure to the benefit of ratepayers, shall be applied to reduce transition costs. St.1997, c.164, i 193 (G.L. c.164, i 1 A(b)(3)). In a settled restmeturing plan, the Depanment found tha; an incentive for an electric company to reduce transition costs can inure to the benefit of ratepayers. D.P.U./D.T.E. 96-24, at 84 (1997). In particular, the Depanment found that an incentive can motivate a company to (1) seek the highest price for its divested assets while minimizing its transaction costs in doing so and (2) renegotiate above-market PPAs more aggressively and creatively than command type regulation could i induce. 11 The record shows that, under the Plan, the Companies would receive incentive i j J 2
,j ..
D.P.UJD.T.E. 97-111 Page 69
~
payments for merely charging transition costs at the forecasted level, would receive no additional payments for large reductions in transition costs that would funher benefit ratepayers, and could receive incentive payments for changes in which the Companies play no role, such as for an increase in the market price for electricity or load growth above the C-:=nias' forecasts, or for a higher forecast of market prices by a purchaser of above- i market PPAs. The record shows that most of the incentive payments (61 percent for , Commonwealth and 82 percent for Cambridge) are tied to the base-case level of the access l charge rather than the amount of actual mitigation achieved, and flow to the Companies regardless of any mitigation. In contrast, most of the incentive payments (57 to 59 percent i for MECo, EECo, and BECo) in restructuring settlements approved by the Depamnent flow I to those companies based on actual mitigation, with only a minority of the payments tied to the base-case level of the access charge (MECo Restructuring Plan, Book 2, at 65; EECo Restructuring Plan, Vol. 2, at 57; BECo Restructuring Plan at 244). The Department approved those incentive plans, overlooking some incentive payments not tied to mitigation, J because most of the incentive payments were tied to actual mitigation. In this case, however, most of the incentive payments are not tied to actual mitigation. Recognizing this crucial j i difference, the Department finds that most of the Companies' proposed incentives, since they are not tied to actual mitigation accomplished, do not encourage aggressive mitigation and therefore do not inure to the benefit of ratepayers. Accordingly, the Depanment directs the Companies to modify their incentive proposal so that all of it inures to the benefit of ratepayers, by tying incentive payments to actual
,'e ..'..
4 1 D.P.UJD.T.E. 97-111 Page 70 mitigation results." The Department reiterates its view that a properly designed incentive can i inure to the benefit of ratepayers, by aligning the financial interests of shareholders and
- ratepayers and by motivating the Companies to maximize the net proceeds of divestiture and mitigate the transition costs from above-market PPAs as creatively and fully as possible. The
] 4- proposed modified incentives should be substantial enough and stmetured appropriately to
- induce mitigation efforts, resulting in larger rate reductions than would otherwise occur.
i Such incentives would comply with the intent of the I.egislature that any incentive mechanism result in lower transition costs and therefore benefit ratepayers. The modified incentive proposal must be filed within 30 days and before final bids are submitted in the Companies' divestiture and PPA auctions.
- 6. Return on Eauity for Transition Charne Calculation
- a. The Act The Act specifies that the return on equity (" ROE") that a distribution company may include as part ofits transition charge calculation shall be determined as follows:
(i) If the transition charge is less than or equal to 1.0 cent per KWH, the ROE shall be no more than one hundred basis points above the ROE allowed by the Department in i its most recent adjudicated rate proceeding. (ii) If the transition charge is more than 1.0 cent per KWH but not more than 2.0 cents per KWH, the ROE shall be the rate in (i) above, less one basis point for each 0.01 cents per KWH that the transition charge is above 1.0 cent per KWH.
" The Department notes that Mr. Kirkwood, who is in charge of the Companies'
( mitigation efforts, testified that he had not considered the incentive in designing and
\. implementing the Companies' mitigation efforts to date (Tr. 3, at 87-88).
- 1 ' :.'.
D.P.UJD.T.E. 97-111 Page 71 (iii). If the transition charge is above 2.0 cents per KWH, the ROE shall be no more I than the ROE in (i) above, less one hundred basis points, and less an additional two basis
}
points for each 0.01 cent per KWH that the transition charge is more than 2.0 cents per KWH t
"above the market price for power provided under comparable terms." St.1997,c.164, l 6 193 (G.L. c.164, i 1E).
- b. The Plan The Companies' Plan uses an ROE of 10.80 percent for Commonwealth and 9.90 percent for Cambridge in the calculation of the transition charge (Exh. CEC-1, Tab H at 4; Tab G at 3).
- c. Positions of the Panies (i) Attorney General
( ' According to the Attorney General, in subsection (iii) of the description of the Act above, the last ten words in quotation marks including the market price in the comparison with the transition charge are the result of a drafting error (Attomey General Brief at 29). The Attomey General gives three reasons to support his contention. First, the last ten words j in (iii) above destroy the parallelism between (ii) and (iii) above (ii). Second, the last ten ! I words destroy the inverse relationship between the ROE and the level of the transition charge (ii). Third, the Attorney General argues that inclusion of the market price in the comparison with the transition charge makes no sense because then the ROE varies inversely with the market price for power over which the Companies have no control (ii). According to the Attorney General, it is " obvious" that the Legislature intended and that " common sense" suggests a mitigation incentive that rewards or penalizes a company for (,
i
.< ,/.
j D.P.U/D.T.E. 97-111 Page 72 factors over which the company has control, such as the level of the transition charge (ii). The Attorney General argues that the Department must disregard the last ten words of the referenced section of the Act; otherwise, it will be disregarding the intent of the Legislature (hl). Using his interpretation of the Act, the Attorney General calculates an ROE of 6.48 percent for Commonwealth and 9.54 percent for Cambridge (11 at 28). (ii) Companies ! The Companies argue that the Attorney General cannot ignore the language of the Act, because the meaning of the words is clear, and the Act is " detailed and comprehensive" (Companies Reply Brief at 41). Further, the Companies argue that the ROE of 6.48 percent that the Attorney General calculates based on his interpretation of the Act is lower than
, Commonwealth's debt rate and the return set by the Department. Therefore, the Companies assert that following the Attorney General's recommendation would clearly be confiscatory for Commonwealth (hL at 41). Noting that "[s]tatutes must be interpreted harmoniously with l
i the Constitution," the Companies state that the Attorney General's interpretation does not meet ; this standard (11 at 42). i
- d. Analysis and Findines The Department notes the concerns raised by the Attorney General regarding the problems associated with accepting the language of the Act at face value. In particular, the !
Department notes the violation of an inverse relationship between the level of the transition charge and the return on equity used for calculating the transition charge. Such a violation removes, at least to some extent, the incentive to a distribution company to reduce its 7 transition charge. The Department also notes the Attorney General's argument that adherence
\.
- p. '
I j< . D.P.UJD.T.E. 97-111 - Page 73 l so the language of the Act results in rewarding or penalizing the distribution company for changes in the transition charge due to factors beyond the control of the Companies, such as the market price of power. Nevertheless, the Depanment cannot ignore the plain language of the Act, particularly ; when the Act is detailed and precise. Therefore, we reject the Attomey General's argument i 1 and accept the Companies' proposal for a return on equity of 10.8 percent for Commonwealth I l l
. and 9.9 percent for Cambridge for the purposes of calculating a retum on the fixed !
component of the transition charge. However, if the Legislature revises the section of the Act discussed here, we may, at that time, require an adjustment to the return on equity to be used l for Cambridge's and Commonwealth's transition charge calculations.
- 7. Reconciliation Account: Rate of Return and Base Transition Charne
(- Adiustments
- a. The Plan According to the Compani:s' Plan, the difference between the estimated variable costs l
l included in the transition charge and the actual variable costs will accumulate in a reconciliation account (Exh. CEC-1, Tab H at 9). The reconciliation account will include a j i return equal to the carrying charge for the fixed component of the transition charge, which is equal to 13.51 percent for Commonwealth (ii, Tab H at 4 and 9). According to the Plan, the reconciliation account for Commonwealth will accumulate the differences befween the estimated and actual variable costs until December 31,2000, and on January 1,2001 will be used to adjust the base transition charge either to recover or to repay the under- or over-l l recovery in the reconciliation account (id , Tab H at 9). After January 1,2001, the base ! .r ( transition charge will be adjusted at the end of every year to allow recovery or repayment of l 1
, . ' .* l, D.P.U/D.T.E. 97-111 Page 74 the amount in the reconciliation account (ii). However, the adjustments will be limited to ensure that the transition charge does not exceed 4.26 cents per KWH for Commonwealth (ii). Any amounts in the reconciliation account that would increase the transition charge over the 4.26 cents per KWH limit will be deferred to the following year, and will earn a i
return equal to the carrying charge (it. Tab H at 9-10). 1 Similarly for Cambridge, the reconciliation account will include a return equal to the I carrying charge for the fixed component of the transition charge, which is 12.69 percent 1 (it, Tab G at 3 and 8). However, for Cambridge the first adjustment to the base transition charge will be made on the earlier of January 1,1999 or the date of divestiture. Thereafter, adjustments to the base transition charge will made at the end of each year, with the l adjustments limited to ensure that the transition charge does not exceed 2.73 cents per KWH l ( (it, Tab G at 8). Just as with Commonwealth, any amounts in the reconciliation account that would increase the transition charge over the 2.73 cents per KWH limit will be deferred to the following year, and will earn a return equal to the canying charge (it Tab G at 8).
- b. Positions of the Panies J When asked why they would delay adjustments to the base transition charge of Commonwealth until the year 2001, the Companies stated that if the adjustment were positive, reflecting an under-recovery, before the year 2001 it would cause the transition charge to exceed the initial level of 4.26 cents per KWH (Tr. 7, at 55). However, they did agree to an adjustment to reflect an over-recovery before the year 2001, and provided modified language for that section of the Plan (Tr. 7, at 55: DPU RR-34).
On the issue of the return applied to the reconciliation account, the Companies l l l
D.P.U/D.T.E. 97-111 Page 75 indicated that they used the carrying charge to be consistent with the other distribution t companies that have filed restructuring plans with the Depa tment under settlements (Tr. 7, at 59). The Companies conceded that any under-recoveries in the reconciliation account would be funded by "short-term financing," would not constitute " bondable propeny" and would not require an equity contribution from shareholders (it at 58-59). No other parties commented on this issue.
- c. Analysis and Findings Regarding the delay in adjusting the base transition charge until the year 2001, the Department finds that there is no reason to postpone adjustment of over recoveries.
Ratepayers should see benefits of reduced transition charges as soon as possible. However, l the Department finds that it would not be appropriate to collect under-recov: ries in the k..~ reconciliation account from ratepayers before the year 2001 for Commonwealth, because i such action would cause the transition charge to exceed the initial level of 4.26 cents per KWH set by the Companies in their Plan, in violation of the Act. St.1997, c.164, i 193 l (C.L. c.164, f IG(e)). Therefore, we direct the Companies to modify the section on the reconciliation account in Volume I, Tab H Exhibit IV, page 9, Section 1.2.1 of their Plan in accordance with the Companies' response to DTE-RR-34. The Department notes that no change is required to the section on the reconciliation account for Cambridge because the Plan allows adjustments beginning on the earlier of January 1,1999 or the date of divestiture, and the base transition charge for Cambridge is not fixed for the years 1998 through 2000 as it is for Commonwealth. On the issue of the return to be applied to the balance in the reconciliation account,
'O D.P.U/D.T.E. 97-111 Page 76 the Department finds, based on the Companies' testimony, that the financing of the balance does not require equity contributions from shareholders. Instead, as the Companies testified, short-tenn financing would be used. Therefore, we find that a carrying charge that includes an equity component should not be used to calculate the return on the balance in the reconciliation account, but instead the return should be based on an appropriate interest rate.
The Companies stated that the deferral account that would include the differences between the costs paid to suppliers of electricity and the standard offer generation revenues collected from cunomers, accmes interest at the same rate as customer deposits (Tr. 7, at 181). The Department finds that this is'an appropriate interest rate to be applied to the balance in the reconciliation account. Using the same interest rate for the transition charge reconciliation account and the (- deferral account for standard offer generation costs has another benefit; it removes any bias
- on the part of the Companies in the selection of supply resources for the standard offer. If the return on the reconciliation account is higher, the Companies may have an incentive to use their own PPAs for supplying standard offer service rather than obtaining supplies from the market, because using their own PPAs would put under recoveries in the transition charge account while using market purchases would put under-recoveries in the deferral account.
The Companies argue that using the carrying charge for calculating the return on the , balance in the reconciliation account is consistent with the other restructuring plans that have been filed and approved by the Department. The Department notes that there is a key l difference in the transition charges filed by the other three companies, MECo, EEco, and ( 1 a 4
3 0 D.P.U1D.T.E. 97-111 Page 77 BEco, and those filed by the Companies in this proceeding. The variable component of the transition charge forms a much larger fraction of the total transition charge in this proceeding. Over the period 1998 to 2000, for Cambridge and Commonwealth, the variable component forms from 70 to 92 percent of the total transition charge, while for MECo, EECo, and BECo it forms from 46 to 59 percent of the total transition charge.8' The increased contribution of the variable component of the transition charge justifies the use of an alternative rate of return on the reconciliation account in this proceeding compared to the ' rate of return used in the previously filed restmeturing plans. Based on the foregoing, the Department directs the Companies to use the interest rate used for customer deposits for application to the balance in the reconciliation account.
- 8. Caoital Stmeture to Use for the Tramition Charne
( . l
- a. The Plan I In the calculation of the transition charge, the Companies have included revenues sufficient to provide an overall pre-tax return of 13.51 percent for Commonwealth and 12.69 l percent for Cambridge (Exh. CEC-1, Tab H st 4, and Tab G at 3). These rates of return are The contribution of the variable component of the transition charge to the total ,
transition charge is given in the following table: Comoany J.22g 1222 292Q MECo 50 % 47 % 46% EECo 59% 56 % 55% BECo 55 % 57 % 55% Commonwealth 86 % 87 % 84 % ' Cambridge 70% 92 % 92 % Sources: D.P.U. 96-25, Exh. MECo-1, Vol. 2, at 62; D.P.UJD.T.E. 96-24, Exh. [ ' EECo-1, Vol. 2, at 54; D.P.U./D.T.E. 96-23, Exh. BE-1, at 241; Exh. CEC-1, Tab H, Sch.1, at 1; Exh. CEC-1, Tab G, Sch.1, at 1.
- <.?
D.P.U/D.T.E. 97-111 Page 78 based on the capital stmeture and costs of the retail companies, Cambridge and Commonwealth (ii).
- b. Positions of the Panies
- i. Attomey General "Ihe Attorney General states that using the capital structure of the stand-alone retail cm. ass would be appropriate if the stranded generation investment were on the books of the retail companies (Attorney General Brief at 25). He assens, however, that the bulk of the fixed investments of Cambridge and Commonwealth are on the books of Canal Electric and are supponed by the capital stmeture of Canal (it at 25-26). He, therefore, recommends that the capital stmeture of Canal be used as the basis for the carrying charge for these investments rather than the capital structures of Cambridge and Commonwealth (it
(. at 26). ii. Comoanies The Companies argue that since Cambridge and Commonwealth will compute, and be responsible for, the transition costs, Cambridge's and Commonwealth's capital structures should be used for calculating the transition charge (Companies Reply Brief at 39). Funher, the Companies argue that Canal will be divesting its generating assets and will be retiring its existing debt with the proceeds; therefore, the capital stmeture of Canal "will have no relevance" (ii),
- c. Analysis and Findines The Depanment is not persuaded by the Companies' argument. The Depanment finds that there is no reason for the company which computes the transition costs and is
.' e
'i D.P.U/D.T.E. 97-111 Page 79 responsible for collecting those costs from the ratepayers to be the company whose capital structure is used to calculate the transition charge. The most important crite ion in the decision regarding the appropriate capital structure is which capital structure suppons the investments for which the transition costs are being computed. The Depanment notes that Canal raised the capital for the construction and operation of the generating units owned by it, and Canal's capital structure continues to suppon those investments. Therefore, for those assets that are owned by Canal, we direct the Companies to use Canal's capital structure, including a 10 percent reduction in the return on equity for Canal as was proposed for Cambridge and Commonwealth.
- 9. Calculation of Cost of Debt
- a. The Plan
(' - In the ca.lculation of the transition charge, the Companies have included revenues sufficient to provide an overall pre-tax return of 13.51 percent for Commonwealth and 12.69 percent for Cambridge (Exh. CEC-1, Tab H at 4, and Tab G at 3). This return includes a long-term debt component with a cost of 8.85 percent for Commonwealth and 8.90 percent i for Cambrids (it Tab H, Schedule 1 at 9, Tab G, Schedule 1 at 9).
- b. Positions of the Parties
- i. Attorney General The Attorney General states that the Companies have made errors in the calculation of the cost of debt (Attorney General Brief at 26). According to the Attorney General, the 4
Companies include issuance costs and unamonized loss on reacquired debt as regulatory
, assets, and also reflect these same costs in the debt rate by netting out these issuance costs k
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D.P.U/D.T.E. 97-111 Page 80 k~ from the balance of each debt series before determining the debt cost rate (it at 26-27). According to the Attorney General, this method of dealing with debt costs is in conflict with the Department's precedent established in the Berkshire Gas Company case, D.P.U. 92-210, for two reasons. First, the Attorney General states that these costs should not be included as regulatory assets but should be included only as a component of the debt cost rate (it at 26). Seco x!, according to the Attorney General, even the method used by the Companies to reflect these issuance costs in the cost of debt is inconsistent with the Berkshire precedent (it at 27). l ii. Comoanies The Companies state that the Attorney General " misconstrued the record" on the first issue of including issuance costs as a regulatory asset (Companies Reply Brief at 40). The Companies state that the delit costs of the retail companies have not been included as a segulatory asset, but have been used to adjust the effective cost of debt (ii). Only the debtcosts of Canal have been included as a regulatory asset after being computed in l l accordance with FERC precedent (ii). The Companies assert that because these costs have l l not been otherwise included in rates, they qualify as a regulatory asset (11). Regarding consistery with Department precedent on the method for reflecting debt ! issuance costs, the Companies acknowledge that they made an error and have provided ! revised calculations of the debt rate that they are willing to use to adjust the carrying charger (11).
- c. Analysis and Findjngi l The Department finds that debt issuance costs for Canal have been appropriately 1
(
c ,. ' 1 .,, I l D.P.U/D.T.E. 97-111 Page 81 l ( included as a regulatory asset. The Department notes the conections made by the Companies in the reflection of debt issuance costs in the cost cf debt for Cambridge and Commonwealth, and directs the Companies to incorporate the revised debt rates in their N calculations of transition costs and provide revised rates and schedules. i l
- 10. Esp.ornizine ch=nees in canital structure 1
- a. The Plan The Plan states that the rate of return used for the calculation of the transition charge will be changed to reflect any savings from securitization (Exh. CEC-1, Tab H, at 4, n.2; Exh. CEC-1, Tab G, at 3, n.2). However, the Plan is silent on the effect of other changes in the capital structure on the rate of return.
l
- b. Positions of the Parties
( .i. Attorney General The Attorney General states that according to the Companies' testimony during cross-l examination, they do not intend to pass on to ratepayers the benefits of any refinancings other than those that result from securitization (Attorney General Brief at 30). The Attomey General lists events, other than securitization, that could affect the carrying charge, such as refinancing, equity retirement, or other mechanisms yet to be created, and asserts that the benefits of these changes should flow to ratepayers (it at 30-31). According to the Attorney General, by not changing the transition charge to reflect changes in the capital stmeture, the Companies' Plan violates the mitigation requirements of the Act (it at 30). ii. Comoanies ! The Companies state that the record may not be clear on the issue of passing on to {
3 '. D.P.U/D.T.E. 97-111 Page 82 ratepayers the benefits of changes in the capital stmeture (Companies Reply Brief at 42). The Companies state that they fully intend to adjust the carrying charge rate for the transition charge calculation to reflect changes in the capital stmeture and will " ensure that their Plan comports to this intent" (hl). I ! c. Am1vsis and Findinos The Department agrees with the Attorney General that the benefits of all changes in l the capital stmcrure, not just those achieved through securitization, should flow to ratepayers. 1 i l The Companies have stated their intent to do so and to modify their Plan to comport with l this intent. We therefore direct the Companies to modify their Plan and state explicitly that the carrying charge used for the transition charge calculation will be changed to reflect all changes to the capital structure and that the resulting benefits will be passed on to ratepayers. (. E. Quality of Service l
- 1. The Act !
l The Act requires that the Depanment ensure that the quality and reliability of service l are the same or better than levels that existed on November 1,1997. St.1997, c.164, i 193 (G.L. c.164, { 1F(7)). 1
- 2. Positions of the Panies The Companies have not included any standards for quality of service in their Plan.
In response to an information request from the Depanment asking how the Companies will i ensure that the quality of service provided to customers will not deteriorate after the retail access date, the Companies said that they are committed to providing quality service (Exh. i . DTE 1). Funher, the Companies stated that they are committed to working with the 4 (
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D.P.U/D.T.E. 97-111 Page 83 Department to " establish meaningful benchmarks" for quality of service (ii). No other panies commented on this issue.
- 3. Analysis and Findings Quality of service is an important issue and the Department detennines that it is best addressed through the development of comprehensive quality of service standards. However, ,
l we believe that a generic proceeding would be the appropriate forum for developing these 1 standards, for it would allow a consideration of performance and service quality issues across all distribution companies and would lead to a fair and consistent treatment of all the distribution companies in the Commonwealth. , In the interim peri <xl between the retail access date and the conclusion of the generic proceeding, the Depanment will monitor the service quality of Cambridge and ( Commonwealth to ensure that the quality and reliability of service are the same or better than levels that existed on November 1,1997. If there are problems with the service quality, the Depanment will use its authority to initiate a proceeding to address the problems. ; F. Other Issues
- 1. Demand-Side Management ("DSM")
- a. The Act The Act directs the Department to require a mandatory charge per KWH for all electricity customers of the Commonwealth (except those of municipal light plants) to fund energy efficiency activities, including DSM, in amounts not to exceed the following: 3.3 mills (50.0033),3.1 mills,2.85 mills,2.7 mills,2.5 mills per KWH in each of the years 1998 through 2002, respectively. St.1997, c.164, f 37 (G.L. c. 25, i 19). At least 20
*( .
D.P.UJD.T.E. 97-111 Page g4
- percent of the amount to be spent on residential DSM, and at least 0.25 mills per KWH :
(which charge shall also be continued in the years after 2002), must be spent on comprehensive low-income DSM and education programs, to be implemented through the existing low-income weatherization and fuel assistance program network, and coordinated with all gas and electric companies in the Commonwealth. E The Act authorizes DOER to oversee and coordinate ratepayer-funded DSM in order to achieve goals that include equity in the allocation of funds among customer classes, suppon for " lost opportunity" programs, elimination of market barriers through state-wide market transformation activities, and the provision of weatherization and efficiency services to low-income customers. E at i 50 (G.L. c. 25A, i 11G). The DOER must file a repon annually with the Department on I proposed funding levels for energy efficiency programs, and the Department must review and approve expenditures for programs found to be cost-effective. E Finally, the Act stipulates I that a municipality or group of municipalities that establishes a load aggregation program (" municipal aggregator") may submit for Department approval an energy plan that calls for , the implementation of DSM programs consistent with any state energy goals developed pursuant to chapter 25A or chapter 164." G.L. c.164, i 134(b). If the municipal energy plan is approved, the municipal aggregator may expend monies collected by a distribution company through its energy efficiency charge in an amount not to exceed that contributed by retail customers within the boundaries of the municipal aggregator. E 4
- b. The Plan The Plan includes funding levels that conform to the Act's mandate (Exh. CEC-1 at 56). As outlined in the Plan, the Companies currently implement a broad spectrum of DSM
D.P.U/D.T.E. 97-111 Page 85 programs including services to low-Income customers coordinated with the South Middlesex Opportunity Council and local weatherization assistance program agencies (it at 56). The Companies claim that they will likely continue these programs during the next five years (it at 56). In addition the Companies state that they have undertaken emerging technologies / market transformation efforts and will work with interested parties to detennine which efforts should continue during the five-year period. (ji at 56). The Companies state that they will collaborate with other panies in the f' mal development and subsequent implementation of their five-year energy efficiency plan. The details regarding the annual budgets and specific programs to be offered over the next five year period will be included in the plan which the Companies will file with the Depanment by April 1,1998 (it at 57,60). (, .
- c. Positions of the Parties
- i. The Comnact The Compact states that the Companies' Plan lacks detailed infonnation about how the Companies plan to expend or allocate the energy efficiency funds among interested towns, referring instead to the ongoing five-year collaborative planning process in which the Compact was recently invited to panicipate (Compact Brief at 31). The Compact recommends that the Depanment defer making any decision on the Plan with respect to DSM and alternative energy programs until the Companies submit subsequent filings that can be reviewed by all panies. (it at 3132).
ii. GSB CISR is concerned that any new energy efficiency contracts which the Cwpanies 1 I
\ 9 . (, D.P.U/D.T.E. 97-111 Page 86 enter into may preclude qualifying municipal governments from having access to those committed portions of the funds or from managing certain energy efficiency programs (CISR Brief at 3). CISR recommends that the Companies include in all new contracts with energy i service vendors, provisions to transfer contracts to qualifying municipalities (it at 3-4). The Companies submitted sample contract language to address this concern; however, CISR contends that the language is not specific enough to address their concerns (it at 4). In addition, CISR recommends that the Companies not enter into any new contracts with energy efficiency vendors that extend beyond a year (ii). CISR recommends that the Department determine that the energy efficiency portion of the Plan is not in compliance with the Act and reject the Companies Plan as proposed, or f provide a conditional approval of the Plan pending Depanment review and approval of the ( five year energy efficiency plan (CISR Reply Brief at 4). In addition, CISR urges the Department to find that the Companies have no role in reviewing municipal energy plans, consistent with the requirements of the Act (ii). iii. Attorney General The Attorney General submits that the issue of allocation of dollars for energy efficienc,y programs, including issues raised by CISR, should be resolved in the Companies' five-year DSM plan filing (AG Brief at 36). I (
ij ,*
" D.P.U/D.T.E. 97-111 Page 87 !
iv. The Comoanies The Companies submit that the Plan complies with the requirements to collect and expend funds to suppon energy efficiency programs (Companies Brief at 56). Funhermore, the Companies will collect the $0.0033 per KWH for the balance of 1998, and collections will ieduce each year until 2002, when only $0.0025 per KWH targeted to programs for low-income customers will remain (hl). The Companies assert that they offer a wide range of programs as outlined in the Plan and are panicipating in a collaborative process relating to future program design and annual budgets (hl). The Companies assen that their DSM program is in full compliance with the Act (id.). The Companies state they will continue their collaborative process to develop and refine a comprehensive five-year er.ergy efficiency program which will be filed with the l - Depanment by April 1,1998 (ii). The Companies offer that new programs will stan July 1,1998, subsequent to Depanment approval. In the meantime, the Companies will implement their initial program with collection of a mandatory charge staning March 1,1998 i (ii). t The Companies contend that the Compact's and CISR's concerns regarding allocation of funds are premature (Companies Reply Brief at 54). Funhermore, the Companies state l that they are not opposed to providing the interested panies with the DSM funds. However, funds will be allocated at the appropriate time (11). The Companies note that CISR and the i Compact have not complied with G.L. c.164, i 134(b) by adopting energy plans and filing them with the Department for approval (it). I l The Companies state that they are opposed to CISR's proposal to have the ( l
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i 1 ! D.P.U/D.T.E. 97-111 Page 88 Depanment require the Companies to include contract provisions to transfer energy efficiency contracts to qualifying municipalities (ii). The Companies assen that I municipalities should design and implement their own programs consistent with their l approved plans (ii).
- d. Annivsis and Findines
'Ibe Companies have agreed to the mandatory charges per KWH to fund energy i
efficiency and DSM activities as required by the Act. In addition, the Companies have established an energy efficiency program as required by the Act. All other issues regarding cost allocation or program design can be resolved within the Companies' five-year energy ' ; efficiency program. Thus, the Department finds that the Companies' program for energy l efficiency complies with the Act. The Depanment notes, however, that our approval of the l ( ' ~ Plan is subject to adjustment at such time as the Depanment approves a municipal energy plan in accordance with G.L. c.164, i 134(b). y 2. Renewable Resources I
- a. The Act 1
To suppon the development and promotion of renewable energy projects, the Act authorizes and directs the Department to require a mandatory charge per KWH for all i electricity consumers in the Commonwealth (except those consumers served by a municipal lighting plant that does not supply generation service outside its own service territory or does not open its service territory to competition at the retail level). St.1997, c.164, 6 37 (G.L.
- c. 25, i 20(a)(1)). The Act sets the non-bypassable charge at the following levels
- 0.75 !
mills per KWH in 1998, followed by 1.00,1.25,1.00, and 0.75 mills in each of the years {k i
,- ~
[. , l 4 9 D'.P.U/D.T.E. 97-111 Page 89 1999 to 2002, respectively, and 0.50 mills per KWH thereafter.1 The Act further requires that in each year. 0.25 mills per KWH be dedicated to the retirement or retrofit of municipal solid waste ("MSW") facilities. E (G.L. c. 25, f 20(a)(2)). The revenues generated by this charge shall be remitted to the Massachusetts Technology Park Corporation ("MTPC") cnd deposited into the Massachusetts Renewable Energy Trust Fund (" Fund"). E (G.L. c. 25, f 20(c)). In addition, the Act provides for the continuation of " net metering," for on-site generation or cogeneration facilities, including renewable facilities, of , 60 kilowatts ("KW") or less. E at i 193 (G.L. c.164, i 1G(g)).
- b. The Plan The Plan includes funding levels that conform to the Act's mandate to fund renewable resource programs (Exh. CEC-1 at 56). The Plan states that it is anticipated that the revenues :
( generated will be remitted to the Massachusetts Technology Park Corporation to promote renewable energy in the Commonwealth (id.).
- c. Analysis and Findines There were no comments regarding the Companies proposal for renewable resources.
The Companies have agreed to the mandatory charge ~per KWH as defined in the Act. The Depanment finds that the Companies' Plan for renewable resource programs complies with the Act. VII. CONCLUSION In determining whether the Companies' Plan substantially complies or is consistent with G.L. c.164 and meets the requirements of any other applicable law, the Department has considered the stated purposes and major features of the Act and determined that the
3 - ',, . D.P.U/D.T.E. 97-111 Page 90 { portions of the Plan governed by G.L. c.164 substantially comply or are consistent with the Act, provided that the Companies address in a compliance filing the modifications required by this Order. We find that these ponions of the Plan substantially comply or are consistent with the stated goals and main features of G.L. c.164: provision of customer choice of generation supplier by March 1,1998; a 10 percent rate reduction for customers choosing the standard offer; an accounting of stranded costs and a mitigation plan based on the sale of generating plant and entitlements; a non-bypassable charge to collect stranded costs; the provision of standard offer service for seven years; unbundled rates; a general inflation cap and a cap on the stranded cost charge; default service; continuation of low-income discounts, and universal service. Funber, the Plan does not prevent the Companies from complying with regulations implementing performance standards and rules of conduct regarding ( affiliates. The Depanment also finds that the portions of the Plan addressing renewables and DSM are in full compliance with G.L. c. 25, (( 19, 20. Therefore, the Department finds that the Plan substantially complies or is consistent with G.L. c.164 and is in full compliance with other provisions of the Act. Accordingly, the Depanment hereby approves the Plan and allows it to be implemented. Funher, upon approval of the Companies' compliance filing, the Depanment authorizes the Companies to l collect a transition cost charge as specified in the Act, according to the formulas embodied in j the Plan, as modified. This authorization is contingent upon the Companies commencement of actual mitigation effons, implementation of retail access, and subject to reconciliation as specified in the Act.
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D.P.U/D.T.E. 97-111 Page 91 ( VIII. ORDER Accordingly, after due notice, hearing, and consideration, it is hereby ORDERED That the tariffs M.D.P.U. Nos. 586 through 609, filed by Cambridge - Electric Light Company, and tariffs M.D.P.U. Nos. 336 through 358, filed by l Commonwealth Electric Company, which would apply to electric service consumed on or after the March 1,1998 Retail Access Date, be and hen by are disallowed; and it is FURTHER ORDERED: That Cambridge Electric Light Company and Commonwealth Electric Company shall design and file tariffs in compliance with this Order; ! l and it is l FURTHER ORDERED: That Cambridge Electric Light Company and Commonwealth Electric Company shall comply with all other orders and directives contained ( herein; and it is s l l
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- j D.P.U/D.T.E. 97-111 Page 92
( FURTHER ORDERED: That the new rates shall apply to electricity consumed on l i or after the March 1,1998 Retail Access Date, but unless othenvise ordered by the Department, shall not become effective earlier than seven (7) days after they are filed with supporting data demonstrating that such rates comply with this Order. By Order of the Department, I mmh W Gail Besser, Chair
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age 93 D.P.U./D.T.E. 97-111 ; Dissent in Part The question whether to use 6.5 or 6.7 cents per kilowatthour as the fuel charge component in determining August 1997 rates against which to calculate the Commonwealth ; Electric Company's 10 percent reduction is not easily answered. While the majority plausibly !
- settles on 6.5 cents, the better though admittedly less expedient answer is 6.7 cents. On 4 .
March 1994, both Commonwealth and the Attorney General of the Commonwealth filed with I the then Department of Public Utilities a joint motion to approve an Offer of Settlement to stabilize Commonwealth's fuel charge for the four years through 1997 (titled the " Fuel Charge Stabilization Settlement", hereafter " settlement"). The Department allowed the joint motion and approved the settlement. Commonwealth Electric r'amanny, D.P.U. 94-3A, at 15 (1994). l The settlement, according to the Order approving it, was designed "to cap the fuel charge . . . at 6.7 cents per KWH for the founh year,1997," although the charge could be as : low as 6.5 cents if Commonwealth sought to defer recovery of actual costs incurred between ! 6.5 and 6.7 cents. Id., at 4. The settlement proposal is consistent with this characterization (see Exh. CEC-6, at 1 [I.A.I.) in D.P.U. 94-3A). The Department found the stabilization proposal to be "in the public interest." Commonwealth, D.P.U. 94-3A, at 14. The
. Department's Order was not appealed; and thus its " legislative" action in allowing this rate ,
level for 1997 took on the force of law. The legally adopted rate for 1997 was capped at 6.7 l cents. _ Throughout 1997, Commonwealth, however, elected, as permitted by the approved ' settlement, to forego taking advantage of the authorized 6.7-cent ceiling and to continue to ; charge 6.5 cents instead. Although deferral entails regulatory risk, Commonweahh chose to I (. accumulate uncollected costs in its stabilization deferral account for recovery over the next six years. See, e.g., Commonwealth Electric Company, D.P.U. 97-3B, at 2-4 (1997) (fuel charge order for the July-September 1997 quarter). It appears that during August 1997, Commonwealth underrecovered by $1.945 million below its actual fuel costs, in whole or part ' because of its election to reduce the quarterly fuel charge below the 6.7 cent cap authorized in , the Order approving the settlement. The fuel charges that, absent the settlement cap of 6.7 cents, could have been levied in 1997 can be derived from the Department fuel charge orders for that year. In the first calendar quarter, Commonwealth deferred $3.718 million to avert a , fuel charge of 6.907 cents; in the second quarter, $2.539 million to aven a charge of 6.822 ! cents; in the fourth quarter, $0.61 million to avert a charge of 6.572 cents. See tables to Commonwenith htric Company, D.P.U. 96 3D,97-3A,97-3B, and 97-3C. Recoverable ' costs were accruing, but its customers were enjoying fuel charge stability. In late 1997, the Restructuring Act, St.1997, c.164, was passed. G.L. c.164, sec. l A(a), as amended by St.1997, c.164, sec.193, now requires that a 10 percent reduction for customer choosing the standard service transition rate be calculated from "the average of undiscounted rates for the sale of electricity in effect during August 1997 or such other date as , the department may determine (emphasis added)." The Restructuring Act offers no dermition of the the term 'undiscounted'; and the notion of ' discount' is not a term of art peculiar to the utility field.' The term is a common, rather than a technical, word; and so, in accordance with G.L. c. 4, sec. 6, cl. Third, the term should be " construed according to the common and approved usage of the language." Even with the assistance of the definitions of the root word _ _ _ _ _ _ _ _ . _ _ _ _ _ . _ _ _ _ _ _ _ _ , . _ . _ - .__ _ . . . .,m.., , , __
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- D.P.U/D.T.E. 97-111 Appeal as to matten of law from any fmal decision, order or mling of the Commission may i s
be taken to the Supreme Judicial Court by an aggrieved pany in interest by the filing of a written petition praying that the Order of the Commistion be modified or set aside in whole i or in pan. l Such petition for appeal shall be filed with the Secretary of the Commission within twenty days after the date of service of the decision, order or mling of the Commission, or within such further time as the Commission may allow upon request filed prior to the expiration of twenty days after the date of service of said decision, order or ruling. Within ten days after such petition has been filed, the appealing pany shall enter the appeal in the Supreme . Judicial Coun sitting in Suffolk County by filing a copy thereof with the Clerk of said Court. (Sec. 5, Chapter 25, G.L. Ter. Ed., as most recently amended by Chapter 485 of the Acts of 1971). i C i 1 1 (
l 4 to e
' discount" in such recognized authorities as Merriam-Webster's Third New Internationa[*8' N Dictionary, Barron's Dictionary of Finance and Investment Terms (4th ed.), and Black's Iaw
( Dictionary (6th ed.), one is hard-pressed to regard Commonwealth's foregoing of the authorized G.7 cent charge for a voluntarily elected 6.5 cent charge in August 1997, and the consequent deferral of cost-recovery in the interest of stabilization, as anything other than a discounted rate. Regardless what wordplay one might engage in, the underlying reality is discount. Thus, the choice of 6.5 cents would appear to flout the statutory directive to use "undiscounted rates." The rate cap of 6.7 cents allowed by the approved settlement and l evidently warrantable by actual costs incurred would seem to be the better choice'. Admittedly, electric restructuring entails many untidy features, notfully provided for in a generally thoughtful statute; and the instant matter is just one of these. In fact, restructuring was undertaken because the old regulatory regime had ceased to work efficiently and because markets offer better consumer protections than cumbersome regulation. That regime needed to be propped up by increasingly anomalous features to make it work, and the fuel charge stabilization plan at issue here is a case in point. Trying to accomodate such anomalies in the transition to a more competitive regime is just one more untidy feature of the process. A plan once proposed by Commonwealth and the Attorney General to benefit ratepayers and found by the Department to be in the public interest should not now backfire on one of the proponents. Perhaps, in the end, the choice of 6.5 versus 6.7 is more akin to the famous gestalt figure in which one alternately sees two opposing profiles and a vase on a dark ground. But I think not. Although it may be expedient for Attorney General now to disavow his offspring (Anorney General Brief, at 9), a regard for fairness, rather than preferred outcome, requires that the Department not seek to avoid the--perhaps unforeseen but nonetheless logical -- outcome ofits approval of the 1994 settlement. The choice of 6.5 cents urged upon the (. Department is opportunistic rather than fair. ' Apart from this point and its consequences for other features of the Final Order in this docket, Ijoin in the remainder of the decision. ames Connelly Commissioner l 4
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