-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, PQqaARklkc2dYI1I5CdAYfGLht+e0f0PMbIjqSUORaBLmz7v1QrgmEQDrlias4wf dubuwm639n3JTHXB3bBv7g== 0000071297-95-000048.txt : 19950623 0000071297-95-000048.hdr.sgml : 19950623 ACCESSION NUMBER: 0000071297-95-000048 CONFORMED SUBMISSION TYPE: 10-K405/A PUBLIC DOCUMENT COUNT: 22 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19950622 SROS: BSE SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NEW ENGLAND ELECTRIC SYSTEM CENTRAL INDEX KEY: 0000071297 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041663060 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405/A SEC ACT: SEC FILE NUMBER: 001-03446 FILM NUMBER: 95548437 BUSINESS ADDRESS: STREET 1: 25 RESEARCH DR CITY: WESTBOROUGH STATE: MA ZIP: 01581 BUSINESS PHONE: 5083669011 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MASSACHUSETTS ELECTRIC CO CENTRAL INDEX KEY: 0000063073 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041988940 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405/A SEC ACT: SEC FILE NUMBER: 000-05464 FILM NUMBER: 95548438 BUSINESS ADDRESS: STREET 1: 25 RESEARCH DR CITY: WESTBOROUGH STATE: MA ZIP: 01582 BUSINESS PHONE: 5083669011 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NARRAGANSETT ELECTRIC CO CENTRAL INDEX KEY: 0000069659 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 050187805 STATE OF INCORPORATION: RI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405/A SEC ACT: SEC FILE NUMBER: 001-07471 FILM NUMBER: 95548439 BUSINESS ADDRESS: STREET 1: 280 MELROSE ST CITY: PROVIDENCE STATE: RI ZIP: 02901 BUSINESS PHONE: 4019411400 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NEW ENGLAND POWER CO CENTRAL INDEX KEY: 0000071337 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041663070 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405/A SEC ACT: SEC FILE NUMBER: 001-06564 FILM NUMBER: 95548440 BUSINESS ADDRESS: STREET 1: 25 RESEARCH DR CITY: WESTBOROUGH STATE: MA ZIP: 01582 BUSINESS PHONE: 6173669011 10-K405/A 1 SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 ____________________________ FORM 10-K AMENDMENT NO. 1 (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [Fee Required] For fiscal year ended December 31, 1994 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [No fee Required] Registrant; State of Incorporation or Commission Organization; Address; I.R.S.Employer File Number and Telephone Number Identification No - ------------ ---------------------- ------------------ 1-3446 NEW ENGLAND ELECTRIC SYSTEM 04-1663060 (A Massachusetts voluntary association) 25 Research Drive Westborough, Massachusetts 01582 Telephone: 508-389-2000 1-6564 NEW ENGLAND POWER COMPANY 04-1663070 (A Massachusetts corporation) 25 Research Drive Westborough, Massachusetts 01582 Telephone: 508-389-2000 0-5464 MASSACHUSETTS ELECTRIC COMPANY 04-1988940 (A Massachusetts corporation) 25 Research Drive Westborough, Massachusetts 01582 Telephone: 508-389-2000 1-7471 THE NARRAGANSETT ELECTRIC COMPANY 05-0187805 (A Rhode Island corporation) 280 Melrose Street Providence, Rhode Island 02907 Telephone: 401-784-7000 Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. (X) Yes ( ) No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (X) The purpose of this Amendment is to file electronically with the Commission those exhibits to the Form 10-K for the year ended December 31, 1994, previously supplied in paper format. New exhibit indexes are supplied for each filing company. NEW ENGLAND ELECTRIC SYSTEM SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No. 1 to Form 10-K to be signed on its behalf, by the undersigned thereunto duly authorized. NEW ENGLAND ELECTRIC SYSTEM s/John G. Cochrane ____________________________ John G. Cochrane Attorney-in-fact Date: June 22, 1995 The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an agreement and declaration of trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which as amended has been filed with the Secretary of the Commonwealth of Massachusetts. Any agreement, obligation or liability made, entered into or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer or agent thereof assumes or shall be held to any liability therefor. NEW ENGLAND POWER COMPANY SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No. 1 to Form 10-K to be signed on its behalf, by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company. NEW ENGLAND POWER COMPANY s/John G. Cochrane ____________________________ John G. Cochrane Attorney-in-fact Date: June 22, 1995 MASSACHUSETTS ELECTRIC COMPANY SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No. 1 to Form 10-K to be signed on its behalf, by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company. MASSACHUSETTS ELECTRIC COMPANY s/John G. Cochrane ____________________________ John G. Cochrane Attorney-in-fact Date: June 22, 1995 THE NARRAGANSETT ELECTRIC COMPANY SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Amendment No. 1 to Form 10-K to be signed on its behalf, by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company. THE NARRAGANSETT ELECTRIC COMPANY s/John G. Cochrane ____________________________ John G. Cochrane Attorney-in-fact Date: June 22, 1995 EX-99 2 NEES EXHIBIT INDEX --------------- Exhibit No. Description Page - ----------- ----------- ---- (3) Agreement and Declaration of Filed herewith Trust dated January 2, 1926, as amended through April 28, 1992 (4)(a) Massachusetts Electric Company Previously First Mortgage Indenture and filed Deed of Trust, dated as of July 1, 1949, and twenty supplements thereto (4)(b) The Narragansett Electric Previously Company First Mortgage Indenture filed and Deed of Trust, dated as of September 1, 1944, and twenty-one supplements thereto (4)(c) The Narragansett Electric Previously Company Preference Provisions, filed as amended, dated March 23, 1993 (4)(d) New England Power Company General Previously and Refunding Mortgage Indenture filed and Deed of Trust dated as of January 1, 1977 and nineteen supplements thereto (10)(a) Boston Edison Company et al. and Previously New England Power Company: filed Amended REMVEC Agreement dated August 12, 1977 (10)(b) The Connecticut Light and Power Previously Company et al. and New England filed Power Company: Sharing Agreement for Joint Ownership, Construction and Operation of Millstone Unit No. 3 dated as of September 1, 1973, and Amendments thereto; Transmission Support Agreement dated August 9, 1974; Instrument of Transfer to NEP with respect to the 1979 Connecticut Nuclear Unit, and Assumption of Obligations, dated December 17, 1975 NEES EXHIBIT INDEX ------------- (10)(c) Connecticut Yankee Atomic Power Previously Company et al. and New England filed Power Company: Stockholders Agreement dated July 1, 1964; Power Purchase Contract dated July 1, 1964; Supplementary Power Contract dated as of April 1, 1987; Capital Funds Agreement dated September 1, 1964; Transmission Agreement dated October 1, 1964; Agreement revising Transmission Agreement dated July 1, 1979; Guarantee Agreement dated as of November 13, 1981; Guarantee Agreement dated as of August 1, 1985 (10)(d) Maine Yankee Atomic Power Company Previously et al. and New England Power filed Company: Capital Funds Agreement dated May 20, 1968 and Power Purchase Contract dated May 20, 1968; Amendments dated as of January 1, 1984, March 1, 1984, October 1, 1984, and August 1, 1985; Stockholders Agreement dated May 20, 1968; Additional Power Contract dated as of February 1, 1984; Guarantee Agreement dated as of September 23, 1985 (10)(e)(i) New England Energy Incorporated Previously Capital Funds Agreement with filed NEES dated November 1, 1974 and Amendments thereto (10)(e)(ii) New England Energy Incorporated Previously Loan Agreement with NEES dated filed July 19, 1978 and effective November 1, 1974, and Amendments thereto (10)(e)(iii) New England Energy Incorporated Previously Fuel Purchase Contract with filed New England Power Company dated July 26, 1979, and Amendments thereto (10)(e)(iv) New England Energy Incorporated Previously Partnership Agreement with filed Samedan Oil Corporation as Amended and Restated on February 5, 1985 and Amendment thereto NEES EXHIBIT INDEX ------------- (10)(e)(v) New England Energy Incorporated Previously Credit Agreement dated as of filed April 28, 1989 and Amendments thereto (10)(e)(vi) New England Energy Incorporated Previously Capital Maintenance Agreement filed dated November 15, 1985, and Assignment and Security Agreement dated November 15, 1985 and Amendment thereto (10)(f) New England Power Company and Previously New England Electric Transmission filed Corporation et al.: Phase I Terminal Facility Support Agreement dated as of December 1, 1981 and Amendments thereto; Agreement with respect to Use of the Quebec Interconnection dated as of December 1, 1981 and Amendments thereto; Agreement for Reinforcement and Improvement of New England Power Company's Transmission System dated as of April 1, 1983; Lease dated as of May 16, 1983; Upper Development - Lower Development Transmission Line Support Agreement dated as of May 16, 1983 (10)(g) New England Electric Transmission Previously Corporation and PruCapital filed Management, Inc. et al: Note Agreement dated as of September 1, 1986; Mortgage, Deed of Trust and Security Agreement dated as of September 1, 1986; Equity Funding Agreement with New England Electric System dated as of December 1, 1985 (10)(h) Vermont Electric Transmission Previously Company, Inc. et al. and New filed England Power Company: Phase I Vermont Transmission Line Support Agreement dated as of December 1, 1981 and Amendments thereto (10)(i) New England Power Pool Previously Agreement and Amendments thereto filed NEES EXHIBIT INDEX ------------- (10)(j) Public Service Company of New Previously Hampshire et al. and New England filed Power Company: Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units dated as of May 1, 1973 and Amendments thereto; Transmission Support Agreement dated as of May 1, 1973; Instrument of Transfer to NEP with respect to the New Hampshire Nuclear Units and Assumptions of Obligations dated December 17, 1975; Agreement Among Participants in New Hampshire Nuclear Units, certain Massachusetts Municipal Systems and Massachusetts Municipal Wholesale Electric Company dated May 28, 1976; Seventh Amendment To and Restated Agreement for Seabrook Project Disbursing Agent and Amendments thereto; Seabrook Project Managing Agent Operating Agreement dated as of June 29, 1992, and Amendment to Seabrook Project Managing Agent Agreement dated as of June 29, 1992 (10)(k) Vermont Yankee Nuclear Power Previously Corporation et al. and New filed England Power Company: Capital Funds Agreement dated February 1, 1968, Amendment dated March 12, 1968, and Power Purchase Contract dated February 1, 1968 and Amendments thereto; Additional Power Contract dated as of February 1, 1984; Guarantee Agreement dated as of November 5, 1981 (10)(l) Yankee Atomic Electric Company Previously et al. and New England Power filed Company: Amended and Restated Power Contract dated April 1, 1985 and Amendments thereto (10)(m) New England Electric Companies' Previously Deferred Compensation Plan as filed amended dated December 8, 1986 NEES EXHIBIT INDEX ------------- (10)(n) New England Electric System Previously Companies Retirement Supplement filed Plan as amended dated April 1, 1991 (10)(o) New England Electric Companies' Previously Executive Supplemental Retirement filed Plan as amended dated April 1, 1991 (10)(p) New England Electric Companies' Previously Incentive Compensation Plan as filed amended dated January 1, 1992 (10)(q) New England Electric Companies' Previously Senior Incentive Compensation filed Plan as amended dated November 26, 1991 (10)(r) New England Electric Companies' Previously Incentive Compensation Plan II filed as amended dated September 3, 1992 (10)(s) New England Electric System Previously Directors Deferred Compensation filed Plan as amended dated November 24, 1992 (10)(t) Forms of Life Insurance Program Previously and Form of Life Insurance filed (Collateral Assignment) (10)(u) New England Power Company and Previously New England Hydro-Transmission filed Electric Company, Inc. et al: Phase II Massachusetts Transmission Facilities Support Agreement dated as of June 1, 1985 and Amendments thereto (10)(v) New England Power Company and Previously New England Hydro-Transmission filed Corporation et al: Phase II New Hampshire Transmission Facilities Support Agreement dated as of June 1, 1985 and Amendments thereto (10)(w) New England Power Company et Previously al: Phase II New England Power filed AC Facilities Support Agreement dated as of June 1, 1985 and Amendments thereto NEES EXHIBIT INDEX ------------- (10)(x) New England Hydro-Transmission Previously Electric Company, Inc. and New filed England Electric System et al: Equity Funding Agreement dated as of June 1, 1985 and Amendments thereto (10)(y) New England Hydro-Transmission Previously Corporation and New England filed Electric System et al: Equity Funding Agreement dated as of June 1, 1985 and Amendments thereto (10)(aa) Ocean State Power, et al., and Previously Narragansett Energy Resources filed Company: Equity Contribution Agreement dated as of December 29, 1988; Amendment dated as of September 29, 1989 Ocean State Power, et al., and Previously New England Electric System: filed Equity Contribution Support Agreement dated as of December 29, 1988; Amendment dated as of September 29, 1989; Ocean State Power II, et al., Previously and Narragansett Energy Resources filed Company: Equity Contribution Agreement dated as of September 29, 1989 Ocean State Power II, et al., Previously and New England Electric System: filed Equity Contribution Support Agreement dated as of September 29, 1989 (10)(bb) New England Power Service Previously Company and Joan T. Bok: filed Service Credit Letter dated October 21, 1982 (10)(cc) New England Electric System Previously and John W. Rowe: Service filed Credit Letter dated December 5, 1988 (10)(dd) New England Power Service Previously Company and the Company: filed Form of Supplemental Pension Service Credit Agreement NEES EXHIBIT INDEX ------------- (10)(ee) New England Electric System Filed herewith and Frederic E. Greenman: Service Credit Letter dated February 23, 1994 (10)(ff) New England Electric System Filed herewith and John W. Newsham: Pension Service Credit Agreement dated February 23, 1994 (13) 1994 Annual Report to Filed herewith Shareholders (21) Subsidiary list Previously filed (24) Power of Attorney Filed herewith (27) Financial Data Schedule Filed herewith NEP EXHIBIT INDEX ------------- Exhibit No. Description Page - ----------- ----------- ---- (3)(a) Articles of Organization as Previously amended through June 27, 1987 filed (3)(b) By-laws of the Company as Previously amended June 25, 1987 filed (4) General and Refunding Mortgage Previously Indenture and Deed of Trust filed dated as of January 1, 1977 and nineteen supplements thereto (10)(a) Boston Edison Company et al. Previously and the Company: Amended filed REMVEC Agreement dated August 12, 1977 (10)(b) The Connecticut Light and Power Previously Company et al. and the Company: filed Sharing Agreement for Joint Ownership, Construction and Operation of Millstone Unit No. 3 dated as of September 1, 1973, and Amendments thereto; Transmission Support Agreement dated August 9, 1974; Instrument of Transfer to the Company with respect to the 1979 Connecticut Nuclear Unit, and Assumption of Obligations, dated December 17, 1975 (10)(c) Connecticut Yankee Atomic Power Previously Company et al. and the Company: filed Stockholders Agreement dated July 1, 1964; Power Purchase Contract dated July 1, 1964; Supplementary Power Contract dated as of April 1, 1987; Capital Funds Agreement dated September 1, 1964 Transmission Agreement dated Previously October 1, 1964; Agreement filed revising Transmission Agreement dated July 1, 1979; Five Year Capital Contribution Agreement dated November 1, 1980; Guarantee Agreement dated as of November 13, 1981; Guarantee Agreement dated as of August 1, 1985 NEP EXHIBIT INDEX ------------- (10)(d) Maine Yankee Atomic Power Previously Company et al. and the Company: filed Capital Funds Agreement dated May 20, 1968 and Power Purchase Contract dated May 20, 1968; and Amendments thereto; Stockholders Agreement dated May 20, 1968; Additional Power Contract dated as of February 1, 1984; Guarantee Agreement dated as of September 23, 1985 (10)(e) Mass. Electric and the Company: Previously Primary Service for Resale dated filed February 15, 1974; and Amendments thereto Memorandum of Understanding Filed herewith effective May 22, 1994 (10)(f) The Narragansett Electric Previously Company and the Company: filed Primary Service for Resale dated February 15, 1974 and Amendments thereto; Memorandum of Understanding effective May 22, 1994 (10)(g) Time Charter between Previously Intercoastal Bulk Carriers, filed Inc., and New England Power Company dated as of December 27, 1989 (10)(h) New England Electric Previously Transmission Corporation et al. filed and the Company: Phase I Terminal Facility Support Agreement dated as of December 1, 1981; Amendments dated as of June 1, 1982 and November 1, 1982; Agreement with respect to Use of the Quebec Interconnection dated as of December 1, 1981; Amendments dated as of May 1, 1982 and November 1, 1982; Amendment dated as of January 1, 1986; NEP EXHIBIT INDEX ------------- (10)(h) Agreement for Reinforcement (cont.) and Improvement of the Company's Transmission System dated as of April 1, 1983; Lease dated as of May 16, 1983; Upper Development-Lower Development Transmission Line Support Agreement dated as of May 16, 1983 (10)(i) Vermont Electric Transmission Previously Company, Inc. et al. and the filed Company: Phase I Vermont Transmission Line Support Agreement dated as of December 1, 1981 and Amendments thereto (10)(j) New England Energy Incorporated Previously and the Company: Fuel Purchase filed Contract dated July 26, 1979, and Amendments thereto (10)(k) New England Power Pool Previously Agreement and Amendments filed thereto (10)(l) New England Power Service Filed herewith Company and the Company: Specimen of Service Contract (10)(m) Public Service Company of New Previously Hampshire et al. and the filed Company: Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units dated as of May 1, 1973 and Amendments thereto; Seventh Amendment as of November 1, 1990; Transmission Support Agreement dated as of May 1, 1973; Instrument of Transfer to the Company with respect to the New Hampshire Nuclear Units and Assumptions of Obligations dated December 17, 1975 and Agreement Among Participants in New Hampshire Nuclear Units, certain Massachusetts Municipal Systems and Massachusetts Municipal Wholesale Electric Company dated May 28, 1976; Seventh Amendment To and Restated Agreement for Seabrook NEP EXHIBIT INDEX ------------- (10)(m) Project Disbursing Agent dated (cont.) as of November 1, 1990; Amendments dated as of June 29, 1992 Settlement Agreement dated as Previously of July 19, 1990 between filed Northeast Utilities Service Company and the Company Seabrook Project Managing Previously Agent Operating Agreement filed dated as of June 29, 1992; and Amendment thereto (10)(n) Vermont Yankee Nuclear Power Previously Corporation et al. and the filed Company: Capital Funds Agreement dated February 1, 1968, Amendment dated March 12, 1968 and Power Purchase Contract dated February 1, 1968 and Amendments thereto; Additional Power Contract dated as of February 1, 1984; Guarantee Agreement dated as of November 5, 1981 (10)(o) Yankee Atomic Electric Company Previously et al. and the Company: filed Amended and Restated Power Contract dated April 1, 1985 and Amendments thereto (10)(p) New England Electric Companies' Previously Deferred Compensation Plan as filed amended dated December 8, 1986 (10)(q) New England Electric System Previously Companies Retirement Supplement filed Plan as amended dated April 1, 1991 (10)(r) New England Electric Companies' Previously Executive Supplemental Retirement filed Plan as amended dated April 1, 1991 (10)(s) New England Electric Companies' Previously Incentive Compensation Plan as filed amended dated January 1, 1992; New England Electric Companies' Senior Incentive Compensation Plan as amended dated November 26, 1991 NEP EXHIBIT INDEX ------------- (10)(t) Forms of Life Insurance Program Previously and Form of Life Insurance filed (Collateral Assignment) (10)(u) New England Electric Companies' Previously Incentive Compensation Plan II filed as amended dated September 1, 1992 (10)(v) New England Hydro-Transmission Previously Electric Company, Inc. et al. filed and the Company: Phase II Massachusetts Transmission Facilities Support Agreement dated as of June 1, 1985 and Amendments thereto (10)(w) New England Hydro-Transmission Previously Corporation et al. and the filed Company: Phase II New Hampshire Transmission Facilities Support Agreement dated as of June 1, 1985 and Amendments thereto (10)(x) Vermont Electric Power Company Previously et al. and the Company: Phase filed II New England Power AC Facilities Support Agreement dated as of June 1, 1985 and Amendments thereto (10)(y) TransCanada Pipelines Limited Previously and the Company: Firm Service filed Contract for Firm Transportation Service for natural gas dated as of January 6, 1992 and Amendment dated as of March 2, 1992 Amendment dated as of October 29, Filed herewith 1993 (10)(z) Renaissance Energy Ltd. and Filed herewith the Company: Temporary Trans- portation Contract Assignment (capacity swap) for Firm Transportation Service for natural gas dated as of October 27, 1993 Amendment dated as of October 25, Filed herewith 1994 NEP EXHIBIT INDEX ------------- (10)(aa) Algonquin Gas Transmission Previously Company and the Company: X-38 filed Service Agreement for Firm Transportation of natural gas dated July 3, 1992; Amendment dated July 31, 1992 Amendment dated as of April 15, Filed herewith 1994 (10)(bb) ANR Pipeline Company and the Previously Company: Gas Transportation filed Agreement dated July 18, 1990 (10)(cc) Columbia Gas Transmission Previously Corporation and the Company: filed Service Agreement for Service under FTS Rate Schedule dated June 13, 1991 (10)(dd) Iroquois Gas Transmission Previously System, L.P. and the Company: filed Gas Transportation Contract for Firm Reserved Service dated as of June 5, 1991 (10)(ee) Tennessee Gas Pipeline Company Previously and the Company: Firm Natural filed Gas Transportation Agreement dated July 9, 1992 (12) Statement re computation of Previously ratios for incorporation by filed reference into NEP registration statements on Form S-3, Commission File Nos. 33-48257, 33-48897, and 33-49193 (13) 1994 Annual Report to Filed herewith Stockholders (21) Subsidiary list Previously filed (24) Power of Attorney Filed herewith (27) Financial Data Schedule Filed herewith Mass. Electric -------------- EXHIBIT INDEX ------------- Exhibit No. Description Page - ----------- ----------- ---- (3)(a) Articles of Organization of the Previously Company as amended through filed November 15, 1993 (3)(b) By-Laws of the Company as Previously amended through September 15, filed 1993 (4) First Mortgage Indenture and Previously Deed of Trust, dated as of filed July 1, 1949, and twenty supplements thereto (10)(a) Boston Edison Company et al. Previously and Company: Amended REMVEC filed Agreement dated August 12, 1977 (10)(b) New England Power Company Previously and the Company: Primary filed Service for Resale dated February 15, 1974; Amendment of Service Agreement dated July 22, 1983; Amendment of Service Agreement effective November 1, 1993; Memorandum of Understanding effective May 22, 1994 (10)(c) New England Power Pool Previously Agreement and Amendments filed thereto (10)(d) New England Power Service Previously Company and the Company: filed Specimen of Service Contract (10)(e) New England Telephone and Previously Telegraph Company and the filed Company: Specimen of Joint Ownership Agreement for Wood Poles (10)(f) New England Electric Companies' Previously Deferred Compensation Plan as filed amended dated December 8, 1986 (10)(g) New England Electric System Previously Companies Retirement Supplement filed Plan as amended dated April 1, 1991 Mass. Electric -------------- EXHIBIT INDEX ------------- (10)(h) New England Electric Companies' Previously Executive Supplemental Retirement filed Plan as amended dated April 1, 1991 (10)(i) New England Electric Companies' Previously Incentive Compensation Plan as filed amended dated January 1, 1992 (10)(j) New England Electric Companies' Previously Form of Deferred Compensation filed Agreement for Directors (10)(k) New England Electric Companies' Previously Senior Incentive Compensation filed Plan as amended dated November 26, 1991 (10)(l) Forms of Life Insurance Program Previously and Form of Life Insurance filed (Collateral Assignment) (10)(m) New England Electric Companies' Previously Incentive Compensation Plan II filed as amended dated September 1, 1992 (10)(n) New England Power Service Previously Company and the Company: filed Form of Supplemental Pension Service Credit Agreement (13) 1994 Annual Report to Filed herewith Stockholders (24) Power of Attorney Filed herewith (27) Financial Data Schedule Filed herewith Narragansett ------------- EXHIBIT INDEX ------------- Exhibit No. Description Page - ----------- ----------- ---- (3)(a) Articles of Incorporation as Previously amended June 9, 1988 filed (3)(b) By-Laws of the Company Previously filed (4)(a) First Mortgage Indenture and Previously Deed of Trust, dated as of filed September 1, 1944, and twenty-one supplements thereto (4)(b) The Narragansett Electric Previously Company Preference Provisions, filed as amended, dated March 23, 1993 (10)(a) Boston Edison Company et al. Previously and the Company: Amended REMVEC filed Agreement dated August 12, 1977 (10)(b) New England Power Company and Previously the Company: Primary Service for filed Resale dated February 15, 1974; Amendment of Service Agreement dated July 24, 1991; Amendment of Service Agreement effective November 1, 1993; Memorandum of Understanding effective May 22, 1994 (10)(c) New England Power Pool Agreement Previously and Amendments thereto filed (10)(d) New England Power Service Previously Company and the Company: filed Specimen of Service Contract (10)(e) New England Telephone and Previously Telegraph Company and the filed Company: Specimen of Joint Ownership Agreement for Wood Poles (10)(f) New England Electric Companies' Previously Deferred Compensation Plan for filed Officers, as amended December 8, 1986 (10)(g) New England Electric System Previously Companies Retirement Supplement filed Plan, as amended April 1, 1991 Narragansett ------------- EXHIBIT INDEX ------------- (10)(h) New England Electric Companies' Previously Executive Supplemental Retirement filed Plan, as amended dated April 1, 1991 (10)(i) New England Companies' Incentive Previously Compensation Plan, as amended filed dated January 1, 1992 (10)(j) New England Electric Companies' Previously Form of Deferred Compensation filed Agreement for Directors (10)(k) New England Electric Companies' Previously Senior Incentive Compensation filed Plan as amended dated November 26, 1991 (10)(l) Forms of Life Insurance Program Previously and Form of Life Insurance filed (Collateral Assignment) (10)(m) New England Electric Companies' Previously Incentive Compensation Plan II filed as amended dated September 1, 1992 (10)(n) New England Power Service Previously Company and the Company: filed Form of Supplemental Pension Service Credit Agreement (12) Statement re computation of Previously ratios for incorporation by filed reference into the Narragansett registration statement on Form S-3, Commission File No. 33-50015 (13) 1994 Annual Report to Filed herewith Stockholders (24) Power of Attorney Filed herewith (27) Financial Data Schedule Filed herewith EX-3 3 EXHIBIT 3 Exhibit 3 CERTIFICATE OF AMENDMENT of the AGREEMENT AND DECLARATION OF TRUST of NEW ENGLAND ELECTRIC SYSTEM We, the undersigned, being two of the Directors and the Secretary of New England Electric System, hereby certify that on April 28, 1992, at a meeting duly called for the purpose on at least twenty (20) days' notice, the shareholders of New England Electric System, by a vote of a majority of the shares present or represented at the meeting, authorized the following amendment to the Agreement and Declaration of Trust of New England Electric System, as previously amended, and that on said day the Board of Directors of New England Electric System by two-thirds vote amended said Agreement and Declaration of Trust, in accordance with the provisions of Article 57 thereof, so that Articles 20, 42, 44, 51, and 54 thereof shall read as follows: Article 20 (the first four sentences): 20. The action of the Board of Directors in respect of any matter shall be by vote or resolution passed by the Board at a meeting. Regular meetings of the Board of Directors may be held at such places and at such times as the Board may by vote from time to time determine, and if so determined no notice thereof need be given. A regular meeting of the Board may be held without notice immediately after and at the same place as the annual meeting of the Shareholders or a special meeting of the Shareholders held in lieu of such annual meeting. A special meeting of the Board of Directors may be held at any time and at any place when called by the president, secretary or two or more Directors, by giving to each of the Directors reasonable notice thereof, and, without implied limitation, a notice thereof, sent through the post-office in a prepaid letter addressed to any Director, at his usual address, and posted in the United States, at least forty-eight (48) hours before such meeting, shall be deemed sufficient notice to such Director, whether the same be received by him or not, and in computing such time Sundays and holidays shall be included. Article 42: 42. An annual meeting of the Shareholders shall be held on the fourth Tuesday of April in every year, or on such other date as the Board of Directors may from time to time fix, at such place designated in the notice, at which meeting the Board of Directors shall lay before the Shareholders financial statements for the last financial year preceding such meeting, and any question may be presented to them or any report of the Board of Directors, or any Director, Trustee, officer, agent or employee of these trusts may be laid before them by the Trustee or by the Board of Directors, president or treasurer of the Company. Purposes for which an annual meeting is to be held additional to those prescribed by law and by these presents may be specified by the Trustee or by the Board of Directors, president or treasurer of the Company. If such annual meeting is omitted on the day herein provided therefor, a special meeting may be held in lieu thereof, and any business transacted or election held at such special meeting shall have the same effect as if transacted or held at the annual meeting. Article 44: 44. The Trustee or the Board of Directors, president or treasurer of the Company may whenever they think fit, and the president or secretary of the Company, upon a written request of the holders of one tenth of all the shares at the time outstanding and carrying the right to vote, shall, call or direct any officer of these trusts to call a special meeting of the Shareholders to be held at such place designated in the notice. Every such request shall express the purpose of the meeting and shall be delivered at the principal office of these trusts addressed to the president or secretary of the Company, and in case the said president or secretary shall refuse or fail, for fourteen (14) days after the request shall have been so delivered, to call such special meeting to be held within thirty (30) days after the delivery of the request, the same may be called by the person or persons signing such request or by any three (3) of them. And a special meeting may also be called by the holders of one tenth of the said shares whenever the offices of the Directors shall be entirely vacant. Article 51: 51. For the purpose of determining the Shareholders who are entitled to receive payment of any dividend, or who are entitled to vote or act at any meeting or any adjourned session thereof, or who are entitled to receive any offering pursuant to Article 31 hereof, the Board of Directors may from time to time close the register and transfer books for such period, not exceeding sixty (60) days, as the Board may determine; or, without closing the said register or transfer books, the Board may fix a time not more than sixty (60) days before the dividend payment date or the meeting or adjourned session or the date of the offering, as of which the Shareholders entitled to such dividend or entitled to vote or act at any meeting or adjourned session or entitled to such offering shall be determined. Article 54: 54. Every notice to any shareholder required or provided for in these presents may be given to him personally or by sending it to him through the post-office in a prepaid letter addressed to him at his address specified in the share register, and posted in the United States, and shall be deemed to have been given at the time when it is so posted. But in respect of any share held jointly by several persons notice so given to any one of them shall be sufficient notice to all of them. And any notice so sent to the registered address of any Shareholder shall be deemed to have been duly sent in respect of any such share whether held by him solely or jointly with others, notwithstanding he be then deceased or be bankrupt or insolvent, and whether the Directors or Trustee or any person sending such notice have knowledge or not of his death, bankruptcy or insolvency, until some other person or persons shall be registered as holders. And the certificate of the person or persons giving such notice shall be sufficient evidence thereof, and shall protect all persons acting in good faith in reliance on such certificate. IN WITNESS WHEREOF we have signed this certificate this 11th day of May, 1992. s/ John W. Rowe ______________________________ Director s/ Joan T. Bok ______________________________ Director s/ Frederic E. Greenman ______________________________ Secretary THE COMMONWEALTH OF MASSACHUSETTS On this 11th day of May, 1992, at Westborough, Massachusetts, before me, a Notary Public within and for the Commonwealth, appeared the above named Joan T. Bok and acknowledged that she acknowledged that she executed the foregoing instrument as her free act and deed. Witness my hand and official seal Westborough, Massachusetts. s/ Renee M. Kossuth ___________________________________ Notary Public My commission expires: April 24, 1998 The foregoing has been duly presented and registered this ____ day of May, 1992. THE FIRST NATIONAL BANK OF BOSTON Trustee of New England Electric System s/ Mark Nelson By: ___________________________________ Authorized Officer EX-10 4 EXHIBIT 10(EE) Exhibit 10(ee) NEW ENGLAND ELECTRIC SYSTEMNew England Electric System 25 Research Drive Westborough, Massachusetts 01582-0001 Telephone: (508) 366-9011 John W. Rowe President and Chief Executive Officer February 23, 1994 Mr. Frederic E. Greenman 25 Research Drive Westborough, MA 01582 Dear Fred: This confirms my oral advice to you of the action taken February 21, 1994, in order to recognize your legal experience prior to joining New England Power Service Company (NEPSCO). It is agreed that, for retirement benefit calculation purposes, your service with NEPSCO will be considered as commencing February 1, 1964; provided, however, your total service for retirement benefit calculation purposes under this letter will not exceed 30 years. A copy of this statement will be placed in your personal file. Very truly yours, s/ John W. Rowe EX-10 5 EXHIBIT 10(FF) Exhibit 10(ff) NEW ENGLAND ELECTRIC SYSTEMNew England Electric System 25 Research Drive Westborough, Massachusetts 01582-0001 Telephone: (508) 366-9011 John W. Rowe President and Chief Executive Officer February 23, 1994 Mr. John W. Newsham 25 Research Drive Westborough, MA 01582 Dear John: This confirms my oral advice to you of the action taken February 21, 1994, in order to recognize your service for New England Power Service Company and its affiliates. It is agreed that upon termination of employment, you will receive in the January following the year in which you terminate employment, a payment as follows: Year of Termination Amount ------------------- ------ 1994 $150,000 1995 120,000 1996 90,000 1997 60,000 1998 30,000 Thereafter 0 A copy of this statement will be placed in your personal file. Very truly yours, s/ John W. Rowe EX-13 6 EXHIBIT 13 [ART WORK APPEARS HERE] Annual Report 1994 [LOGO] NEW ENGLAND ELECTRIC SYSTEM In 1994, NEES delivered its sixth consecutive year of superior earnings, and did so in an increasingly competitive environment, with electric rates that were the lowest among major electric utility systems in New England. [ART WORK APPEARS HERE] New England Electric System The NEES subsidiaries include: Massachusetts Electric Company, The Narragansett Electric Company, and Granite State Electric Company, retail electric companies that provide electricity and related services to 1.3 million customers in 197 communities in Massachusetts, Rhode Island, and New Hampshire; New England Power Company, a wholesale electric generating company that operates five thermal generating stations, 14 hydroelectric generating stations, a pumped storage station, and approximately 2,400 miles of transmission lines; New England Electric Resources, Inc., an independent project development and consulting company that seeks investment opportunities in power plant modernization, transmission, and environmental improvement; New England Electric Transmission Corporation, New England Hydro-Transmission Corporation, and New England Hydro-Transmission Electric Company, Inc., electric transmission companies that developed, own, and operate facilities associated with the high voltage, direct current interconnection between New England and Quebec; Narragansett Energy Resources Company, a wholesale electric generating company that owns 20 percent of the Ocean State Power generating station in Rhode Island; New England Energy Incorporated, an oil and gas exploration and development company; New England Power Service Company, a service company that provides administrative, legal, engineering, and other support to the affiliated NEES subsidiaries. Financial Highlights 1994 1993 ---- ---- Earnings per average share $ 3.07 $ 2.93 Dividends declared per share $2.285 $ 2.22 Book value per share-year end $24.33 $ 23.55 Market price per share-year end $32-1/8 $39-1/8 Growth in kilowatthour (KWH) sales billed to ultimate customers 1.6% 1.4% Cost per KWH to ultimate customers (cents) 9.29 9.50 New England Electric System (NEES) is a public utility holding company headquartered in Westborough, Massachusetts. The NEES family of companies, described on the inside page to the left, constitutes the second largest electric utility system in New England. Core business activities are the generation, transmission, distribution, and sale of electric energy and the delivery of related services, including energy efficiency improvements, to residential, commercial, industrial, and municipal customers. Other business activities include independent transmission projects and energy management consultation. The NEES companies are guided by the following commitment: "We pledge to provide our customers the highest possible value by continuously improving electric service, managing costs, and reducing adverse environmental impacts." Contents Letter to Shareholders 2 Winning in A Changing Business 4 Improving Our Competitive Position 5 Financial Review 16 Financial Statements 25 Notes to Financial Statements 30 Report of Management 43 Report of Independent Accountants 43 Shareholder Information 44 System Directors and Officers - System Subsidiaries 45 Return on Common Equity - 1994 New England Electric System 12.7% Median of U.S. Electric Utilities 11.4% Median of New England/New York Electric Utilities 11.4% To Our Fellow Shareholders The year 1994 was another good one for the New England Electric System (NEES). Among our accomplishments: Earnings per common share increased to $3.07 compared with $2.93 in 1993. Return on equity was 12.7 percent, placing us in the top one-third of major electric utility systems in New England and New York for the sixth consecutive year. This is a record unmatched by any other electric utility in the region Our return on equity also places us in the top quartile of major electric utilities across the nation. Bond ratings for NEES subsidiaries were A+ or higher, reflecting our attention to the balance sheet as well as the income statement. Your dividend was increased to $2.30 per share in May 1994. Dividend growth over the past five years has exceeded both the regional and national averages for major electric utilities. Our fossil-fueled power plants set new records for availability and our demand-side management programs continued to provide both profits for shareholders and savings for customers. While our region has higher energy costs than much of the nation, NEES has consistently performed with superior efficiency. Our current average retail rate of 9.3 cents per kilowatthour is the lowest among major electric utility systems in New England, and is slightly lower than our average rate of each of the past two years. As you know, our share price dropped during 1994, largely as a result of rising interest rates. However, the drop was in line with that experienced by other utilities. Over the past five years, NEES shares have outperformed the average electric utility stock, and our market performance, as measured by market to book ratio, continues to lead the region. During the past year, proposals for increased competition have affected the structure, operations, and financial position of the electric utility industry. While competition has been with us in various forms for many years, the Federal Energy Regulatory Commission (FERC) is now developing ground rules for wide-open competition in wholesale electricity markets, and many state commissions, including those that regulate the NEES retail companies, are evaluating proposals for competition within the traditional retail service franchise. NEES's response to these trends has been to adapt quickly to changing market conditions while preserving our focus on business fundamentals: first, the cost and quality of our service; second, the quality of our assets and the length of our financial commitments; third, the environmental impact of our operations; and finally, the fairness of the rules that regulate our operations. This response has allowed us to continue to profit in a rapidly evolving regulatory environment. [PHOTO OF JOAN BOK Joan T. Bok, APPEARS HERE] Chairman of the Board During 1994, we reached important agreements that reinforce our long-term competitive position. We have signed service extension discount (SED) contracts with 82 percent of our large commercial and industrial customers in Massachusetts and Rhode Island. Through these contracts, customers agree to give us three to five years notice before generating their own electricity or changing electricity suppliers, and in exchange receive a 5 percent base rate discount (see page 17 for details.) An agreement reached in December 1994 with certain state agencies, municipal light departments, and large commercial and industrial customers and approved by the FERC in February 1995 will hold our wholesale subsidiary New England Power's rates at their present level until at least 1997. An agreement with more than a dozen environmental, recreational, and governmental organizations, currently before the FERC for approval, would expedite the relicensing of our hydroelectric generating facilities along the Deerfield River, and has enhanced our reputation for environmental commitment. While the next few years are likely to be difficult for our industry, NEES has a track record of prospering in difficult times. We have continuously been one of the quickest to adapt to new public policies and one of the most efficient in making these policies work. This flexibility has helped us receive fair treatment from regulators. We strive to be less costly, more profitable, more agile, and more green than our competitors. We have hard working, hard thinking employees who want to win, who have a record of winning, and who are determined to continue winning. With their support, we believe our consistent and unequivocal commitment to enhancing shareholder value will make NEES a rewarding investment in the future as it has been in the past. We thank you for your continued investment and confidence in the New England Electric System. s/ Joan T. Bok s/ John W. Rowe Joan T. Bok John W. Rowe Chairman of the Board President and Chief Executive Officer February 27, 1995 NEES' Key Financial Goals - 1994 Results Dividend Growth exceeds average of electric utilities on rolling 5-year average. Return on Equity in top one-third of major New York and New England utilities. Cash Flow coverage of dividend in top one-third of major electric utilities. Investment Quality Auditors' reports not qualified and bond ratings A+. Total Return in top one-third of major electric utilities on rolling 5-year average. Achieved goals in blue Non-achieved goal in gray John W. Rowe, President [PHOTO OF JOHN W. ROWE and Chief Executive Officer APPEARS HERE] Winning in a Changing Business Unique responsibilities and commensurate rights have shaped the evolution of the electric utility industry. In exchange for exclusive rights to supply electricity within franchise areas, utilities have served all customers under rates set by regulators, projected long-term needs for electricity, and built or purchased power from facilities to meet those long-term needs. Shareholders have backed these large capital commitments required to build the facilities due to the promise of an opportunity to earn a fair return on their investments. Historically, utilities built the generating plants, transmission lines, and distribution systems needed within their service territories. In the early 1980s, however, operators of independent generating plants began to compete with utilities to produce power that could be sold on the "wholesale" market to utilities. The Energy Policy Act of 1992 established a national policy favoring more wholesale competition; this policy has been implemented at both the state and federal levels. As wholesale competition grows and various states consider new forms of competition, transmission and distribution wires are likely to remain closely regulated. With the market for electricity and related services becoming more competitive, the operating environment for all electric utilities will become more complex and more risky. A decisive response to these new competitive pressures is essential to maintain our strong financial performance and our regional position as a high-value, low-cost provider of electricity and related services. Here are some examples of the steps we have taken to improve our competitive position. Improving Our Competitive Position Customer Focus 6 Competitive Marketplace 8 Environment 10 New Rules 12 A History of Responding to Challenges 14 Customer Focus We continue to expand the array of energy services we provide directly to our customers. At Dartmouth College in Hanover, N.H., our programs have resulted in energy-efficient lighting in the campus library, athletic facilities, and student cultural center as well as computerized control of heating, ventilation, and air conditioning in one of the science labs. At the college's math and computer science building, we are now implementing a pilot program in which all energy-related equipment and control processes within a single building-not just those involving electricity-are monitored and adjusted to make sure they are performing optimally. A view from the customer's side of the meter led to the development of EnergyFIT-integrated services for energy conservation, power quality, cogeneration assessment, and electrotechnology evaluations that are customized to meet the needs of our largest and most energy-intensive business customers. EnergyFIT makes business customers more efficient, productive, and profitable, and helps to strengthen our relationship with them. EnergyFIT services encouraged Kopin Corporation, a manufacturer of active matrix liquid crystal displays, to establish a new manufacturing facility in Westborough, Mass.; developed ways for Nyman Mfg. Co. in East Providence, R.I. to produce plastic dinnerware at lower energy cost; and helped a 105-year-old firm, Crown Yarn Dye Co., Inc. in Attleboro, Mass., to continue custom dyeing operations for companies throughout the U.S. [ONE HALF OF MORTARBOARD PHOTO APPEARS HERE] In addition to serving existing customers, all of the NEES companies are participating in efforts to attract new businesses to the region. We recognize that many businesses are carefully weighing energy costs before choosing new locations. The Coca-Cola Company chose Northampton, Mass. over two communities served by other electric companies for a bottling plant for its non-carbonated products. Massachusetts Electric created a service package that offered economic development rates and a substantial investment in energy efficiency as part of the pull to attract the plant and the 150 to 250 associated jobs to Northampton. Our success and that of the region are well served by working with customers to get the most for their energy dollars. [ONE HALF OF MORTARBOARD PHOTO APPEARS HERE] Douglas Smith, senior [PHOTO OF DOUGLAS SMITH technical representative, APPEARS HERE] is a member of the Massachusetts Electric team that created a service package to help attract a Coca-Cola Company bottling plant to our service territory. Competitive Marketplace We are increasing our efforts to protect the share of the market that we now serve, increase customer awareness of our new products and services, and develop new business ventures. One emerging market in which NEES has already established a strong position is the construction, operation, and/or ownership of transmission facilities outside our service territory. During the 1980s, we managed the construction of the Hydro-Quebec Phase 1 and 2 direct current interconnection, a large project in which most New England utilities participated. In 1994, Nantucket Cable Electric Company, Inc., a new company established by NEES, was selected to design, construct, and maintain a 27-mile-long undersea and underground transmission cable linking the island of Nantucket to mainland Massachusetts. This project is expected to be in operation in early 1997, and will provide Nantucket residents with improved service, more stable electricity costs, and - because it will replace diesel generators now in use on the island - a more environmentally-friendly energy supply. To pursue transmission projects worldwide, the NEES subsidiary New England Electric Resources, Inc. (NEERI) is teaming up with Sweden's ABB Power Systems, one of the world's leading suppliers of transmission equipment and Paul Stasiuk, senior analyst, evaluates electrotechnologies in the commercial food-service industry for the NEES companies. Much of his recent work involves the electric cooking center at Johnson & Wales University. [PHOTO OF PAUL STASIUK APPEARS HERE] [ONE HALF OF LIGHTHOUSE PHOTO APPEARS HERE] services. NEERI will help provide utility managers worldwide with innovative options for developing and financing transmission systems. These ventures will build on our established leadership in large-scale transmission projects. Promoting clean and efficient electrotechnologies that replace the use of other energy sources is another way for the NEES companies to be the energy supplier of choice. NEES's three retail subsidiaries joined to sponsor a new cooking center at the world's largest college of culinary arts, Johnson and Wales University in Providence. This cooking center is the focal point for evaluating newly developed electric cooking equipment that incorporates features--such as quick temperature adjustment-preferred by many cooks and readily available in competing gas equipment. Showcased as a "high tech cook- off," the center is set up to enable detailed, side-by-side comparisons of commercial gas and electric cooking equipment. Data are being collected to compare the quality of the finished food, overall labor and energy efficiency, and health benefits of food handling for competing state-of-the-art gas and electric cooking technologies. This electric cooking center provides energy- efficient electrotechnologies for our customer, Johnson and Wales; exposes future chefs to the best electric cooking equipment available; and can help to strengthen the market for our core product. [ONE HALF OF LIGHTHOUSE PHOTO APPEARS HERE] Environment Cost-effective environmental improvement will continue to be a fundamental challenge for electric utilities. Success often requires cooperation among many interested parties. In 1994, we advanced our efforts to secure a 40-year federal license for New England Power's eight hydroelectric dams on the Deerfield River with an agreement among environmentalists, anglers, white water enthusiasts, and state and federal resource agencies. The agreement was designed to expedite licensing and avoid litigation. It is the culmination of more than five years of negotiation and will enhance recreation, fisheries, and conservation in the Deerfield Valley. New England Power has made substantial reductions in air emissions a cornerstone of its operational goals. The company remains an industry leader in using innovative emission controls on existing fossil-fueled power plants. Our 1994 emissions, compared with 1990 levels, were 45 percent lower for sulfur dioxide, 23 percent lower for nitrogen oxides, and 11 percent lower for carbon dioxide. In February 1995, we announced a voluntary commitment to reduce greenhouse gas emissions by 20 percent below 1990 levels by the year 2000 as part of President Clinton's Climate Challenge Program. This emissions reduction target is among the most ambitious of the commitments made by participating utilities. [ONE HALF OF CANOE PHOTO APPEARS HERE] [ONE HALF OF CANOE PHOTO APPEARS HERE] The Manchester Street Station repowering project, scheduled for completion in late 1995, will use a more efficient and environmentally-friendly gas-fired power generating technology while more than tripling this Rhode Island plant's output to 489 megawatts (MW). The station is located in a densely populated urban area at the head of Narragansett Bay and across the river from Providence's treasured historic district. Our activities are closely coordinated with other major projects that are revitalizing the Providence downtown and waterfront. We have considered the needs of neighbors in every detail of the plant construction and continue to receive their enthusiastic support. The NEES companies' efforts to promote more sustainable energy supplies include a planned project to produce energy from biomass fuels such as wood and organic waste. We have also received regulatory approval for energy purchases from seven projects that will provide 36 MW of capacity through wind power, waste heat recovery, and the use of landfill methane and municipal solid waste as fuels. Paula Hamel, senior environmental engineer, [PHOTO OF PAULA HAMEL APPEARS HERE] works with contractors and city, state, and federal agencies to ensure that Manchester Street Station repowering activities meet environmental and safety requirements. New Rules Since non-utilities were allowed to enter the wholesale generation market, New England Power has relied on all available options to meet its requirements. During that time, two-thirds of New England Power's new net generating capability has come from independent generating sources and Hydro-Quebec. The company is now working on new rules to make wholesale competition more efficient through reform of the New England Power Pool and the creation of a Regional Transmission Group. We now face various proposals to permit retail competition. A common feature of nearly all such proposals is that utilities would be required to open both their transmission and distribution systems to competitors and to customers. If this happens, the goal of producing a more efficient electricity market will best be accomplished by ensuring that all users of a utility's wires pay their share of all of the costs committed by utilities to build the present electric system. Along with the Conservation Law Foundation, we have proposed a concept, called by some the "Grand Bargain," to recover these fixed costs through a system access charge. As part of this Bargain, the NEES companies would be willing to spin off or sell our transmission system, invest in environmental improvement ahead of new requirements, and continue investments in conservation and renewable energy. The new, independent transmission company would then offer comparable Masheed Hegi, consulting engineer, negotiates transmission agreements [PHOTO OF MASHEED HEGI between the NEES companies and other APPEARS HERE] users and providers of transmission services. She is currently participating in the effort to develop a New England Regional Transmission Agreement. [ONE HALF OF PEN PHOTO APPEARS HERE] transmission access and pricing to all competing power suppliers. This "Grand Bargain" would provide benefits to both customers and shareholders. In the near term, rates could be reduced by lengthening the period over which we recover certain costs. In the long term, rates should also be reduced by increased customer responsibility for generation choices and increased market pressure on suppliers. Shareholders would benefit from clear provisions for the recovery of the cost of past commitments. In Massachusetts, the Division of Energy Resources (DOER) recently proposed that when new generating capacity is needed, retail customers with an aggregate load equal to the needed capacity be allowed to bid for access to utility wires. The winning bidders could then choose their electricity supplier. This proposal would provide customer choice and leave NEES its existing revenue base to pay for its past commitments. We support the DOER proposal. Other proposals for "retail wheeling" would permit access to utility wires at low cost and force generating prices down to short-run operating costs. In our view, these proposals would deny all utilities the opportunity to recover their past commitments to which we believe they are entitled. If retail competition is permitted, a fair system must permit utilities to charge a fee for access to their transmission and distribution system which will enable them to recover all of their fixed costs. In summary, we are exerting all of our efforts to assure that new rules are written under which New England Electric System and other well-run utility systems have an opportunity to succeed in the competitive marketplace. [ONE HALF OF PEN PHOTO APPEARS HERE] A History of Responding to Challenges The 1960s brought about tremendous increases in the demand for electricity, and our wholesale subsidiary expanded its capacity to meet that demand. The 1970s brought about oil embargoes, and we diversified our fuel mix. The late 1970s and early 1980s brought inflation and the high costs associated with the construction of the Seabrook and Millstone 3 nuclear plants; we responded by diversifying our power purchases and by incorporating energy conservation into resource planning. In each of these decades, NEES developed progressive and innovative solutions that allowed us to provide excellent financial results for our shareholders. Now, in the 1990s, increased competition is on the minds of executives and shareholders in the electric utility industry. Our proven ability to anticipate change and successfully adapt is increasingly important in meeting today's challenges. Financial Report Financial Review 16 Financial Statements Selected Financial Data 25 Consolidated Income 26 Consolidated Retained Earnings 26 Consolidated Balance Sheets 27 Cash Flow 28 Capitalization 29 Notes to Financial Statements 30 Report of Management 43 Report of Independent Accountants 43 Shareholder Information 44 Financial Review [GRAPH APPEARS HERE] Overview Earnings in 1994 were $3.07 per share compared with $2.93 and $2.85 per share in 1993 and 1992, respectively. The return on 1994 common equity was 12.7 percent. The improvement in 1994 earnings reflects increased kilowatthour (KWH) sales to ultimate customers, decreased purchased power expense and interest expense, and the amortization of unbilled revenues. In addition, earnings in 1993 were reduced by the one-time effects of an early retirement program and the establishment of additional gas waste reserves. These factors were partially offset by increased operation and maintenance expenses and a temporary rate reduction (see "Retail rate activity" section). The increase in 1993 earnings over 1992 was primarily the result of increased KWH sales, reduced interest costs, and lower costs of scheduled overhauls at wholly-owned thermal generating units, partially offset by the combined effects of the one-time items described above. KWH sales billed to ultimate customers in 1994 increased by 1.6 percent over 1993, reflecting an improved economy. KWH sales in 1993 increased 1.4 percent over 1992 sales, reflecting more normal weather conditions in 1993 compared with 1992, partially offset by the fact that 1992 included an extra day for leap year. New England Electric System (NEES) retail subsidiaries currently forecast an increase in KWH sales of less than 1 percent in 1995. The annual dividend rate was raised by 2.7 percent, or $.06 per share, in May 1994 and is now $2.30 on an annual basis. In 1993, the annual dividend rate was increased by 3.7 percent, or $.08 per share. The market price of NEES common shares at year end 1994 was $32 1/8 per share, compared with $39 1/8 per share and $38 1/2 per share at the end of 1993 and 1992, respectively. Wholesale rate activity In February 1995, the Federal Energy Regulatory Commission (FERC) approved a rate agreement filed by New England Power Company (NEP). Under the agreement, which is effective January 1995, NEP's base rates will be frozen until 1997. Before this rate agreement, NEP's rate structure contained two surcharges which were recovering the costs of a coal conversion project and a portion of NEP's investment in the Seabrook 1 Nuclear Unit (Seabrook 1). Under the rate agreement, these two surcharges, which were due to expire in mid-1995, will be rolled into base rates. The agreement also provides for the costs resulting from the Manchester Street Station repowering project, which is expected to be completed in late 1995, to be included in rate base, without a rate increase (see "Liquidity and capital resources" section). In addition, the agreement allows NEP to recover approximately $50 million of deferred costs associated with terminated purchased power contracts and postretirement benefits other than pensions (PBOPs) over seven years. The agreement also provides for full current recovery of PBOP costs commencing in 1995. The agreement further provides for the recovery over three years of $27 million of costs related to the dismantling of a retired generating station and the replacement of a turbine rotor at one of NEP's generating units. The agreement also increases NEP's recovery of depreciation expense by approximately $8 million annually to recognize costs associated with the eventual dismantling of its Brayton Point and Salem Harbor generating plants. Under the agreement, approximately $15 million of the $38 million in Seabrook 1 costs due to be recovered in 1995 pursuant to a 1988 settlement agreement will be deferred and recovered in 1996. The agreement further allows for deferral of additional purchased power contract termination costs and any increases in nuclear decommissioning payments for recovery in future rates. Yankee Atomic Electric Company, of which NEP is a 30 percent owner, recently announced a new decommissioning cost estimate, which, if approved by the FERC, would increase annual billings to NEP by $11 million, beginning in late 1995 and ending in July 2000. The settlement rates provide for approximately $24 million in revenues in 1996 to complete the amortization of pre-1988 Seabrook 1 costs and the costs associated with the cancelled Seabrook 2 nuclear unit. To the extent the settlement rates stay in effect beyond 1996, the agreement provides that these revenues be applied first to accelerate recovery of deferred PBOP costs, and then to additional amortization of NEP's investment in the Millstone 3 nuclear unit. The FERC's approval of this rate agreement applies to all of NEP's customers except the Town of Norwood, Massachusetts and the Milford Power Limited Partnership (MPLP), who intervened in the rate case. A separate hearing will be conducted to determine the appropriate rate to charge these two parties, who represent less than 2 percent of NEP's sales. Retail rate activity In 1993, the Massachusetts Department of Public Utilities (MDPU) approved a rate agreement filed by Massachusetts Electric Company (Massachusetts Electric), the Massachusetts Attorney General, and two groups of large commercial and industrial customers. Under the agreement, effective December 1, 1993, Massachusetts Electric implemented an 11 month general rate decrease of $26 million (annual basis). This rate reduction continued in effect through October 31, 1994, at which time rates increased to the previously approved levels. Massachusetts Electric also agreed not to further increase its base rates before October 1, 1995. The agreement also provided for the recognition of unbilled revenues for accounting purposes. Unbilled revenues at September 30, 1993 of approximately $35 million were amortized to income over 13 months commencing December 1993. The agreement further provided for rate discounts for large commercial and industrial customers who signed agreements to give a five-year notice to Massachusetts Electric before they purchase power from another supplier or generate any additional power themselves. The notice provision may be reduced from five to three years under certain conditions. The aggregate amount of these service extension discounts (SEDs) was $4 million during 1994 but will increase in 1995 to approximately $10 million per year under the terms of the agreement. The agreement also resolved all rate recovery issues associated with environmental remediation costs of Massachusetts manufactured gas waste sites formerly owned by Massachusetts Electric and its affiliates, as well as certain other Massachusetts Electric environmental cleanup costs (see "Hazardous waste" section). Effective October 1992, the MDPU authorized a $45.6 million annual increase in rates for Massachusetts Electric. In July 1994, the Rhode Island Public Utilities Commission (RIPUC) approved a rate agreement between The Narragansett Electric Company (Narragansett) and the Rhode Island Division of Public Utilities and Carriers that provides for SEDs to large commercial and industrial customers under terms similar to the Massachusetts Electric program described above. The aggregate amount of Narragansett's discounts was $1.5 million in 1994 and is expected to be approximately $3 million per year thereafter. The agreement also provides for Narragansett to recognize unbilled revenues for accounting purposes. Unbilled revenues at December 31, 1993 of approximately $14 million are being amortized to income over a 21 month period that began in April 1994. Each of the NEES retail subsidiaries is likely to file a rate case with its respective state regulatory agency during 1995. Demand-side management The retail companies regularly file their demand-side management (DSM) programs with their respective regulatory agencies and have received approval to recover DSM program expenditures in rates on a current basis. These expenditures were $70 million, $62 million, and $58 million in 1994, 1993, and [GRAPH APPEARS HERE] 1992, respectively. Since 1990, the retail companies have been allowed to earn incentives based on the results of their DSM programs. The retail companies must be able to demonstrate the electricity savings produced by their DSM programs to their respective state regulatory agencies before incentives are recorded. The retail companies recorded before-tax incentives of $7.7 million, $7.3 million, and $10.5 million in 1994, 1993, and 1992, respectively. The retail companies have received regulatory orders that will give them the opportunity to continue to earn incentives based on 1995 DSM program results. [GRAPH APPEARS HERE] Operating revenue Operating revenue increased $9 million in 1994, primarily reflecting increased KWH sales and amortization of unbilled revenues by retail subsidiaries, partially offset by the temporary rate reduction at Massachusetts Electric. KWH sales billed to ultimate customers in 1994 increased by 1.6 percent over 1993, reflecting an improved economy. Operating revenue increased by $52 million in 1993, primarily due to increased KWH sales, retail rate increases, and beginning in the fourth quarter of 1993, the recognition by Massachusetts Electric of unbilled revenues. KWH sales billed to ultimate customers in 1993 increased 1.4 percent over 1992. More normal weather conditions in 1993 compared with 1992 were largely offset by the fact that 1992 included an extra day for leap year. Operating expenses Total operating expenses increased by $15 million in 1994 over 1993, reflecting increases in generating plant maintenance costs associated with overhauls of wholly-owned generating units in part to achieve compliance with the Clean Air Act. Operating expenses in 1994 also reflected cost increases in DSM, computer system development, pension and other retiree benefits, and general increases in other areas. These increases were partially offset by decreases in fuel and purchased power expense due to overhauls and refueling shutdowns of partially-owned nuclear power suppliers in 1993. In addition, 1993 operating expenses included a net amount of $30 million associated with an early retirement and special severance program and the establishment of additional gas waste reserves, partially offset by the effects of a rate settlement that allowed recovery of amounts previously charged to expense. Depreciation and amortization increased $4 million in 1994, reflecting increased amortization of the net investment in Seabrook 1, increased charges for dismantlement of a previously retired generating station, and depreciation of new plant expenditures. These increases were partially offset by decreased oil and gas amortization due to decreased production. Taxes charged to operations in 1994 increased by approximately $12 million, reflecting increased income taxes and municipal property taxes. Total operating expenses increased by $55 million in 1993, reflecting a $28 million charge associated with the early retirement offer referred to above, $10 million due to the adoption of two new accounting standards for postemployment benefits, increased computer systems development costs, and general increases in other areas. These increases were partially offset by a decrease in generating plant maintenance costs and reduced winter storm-related costs. Depreciation and amortization decreased $6 million in 1993, reflecting reduced amortization of oil and gas properties due to decreased production. NEP's expense also declined as a result of new lower depreciation rates established in its 1992 rate case. These decreases were partially offset by increased amortization of Seabrook 1 as part of NEP's 1988 rate settlement and increased depreciation on new plant expenditures. Taxes charged to operations in 1993 increased by approximately $17 million, reflecting higher municipal property taxes and increased income taxes, including the effects of the increase in the federal income tax rate in 1993 from 34 percent to 35 percent. Interest expense Interest expense decreased $6 million and $9 million in 1994 and 1993, respectively, due to significant refinancings of corporate debt at lower interest rates during 1993 and 1992. Allowance for funds used during construction (AFDC) AFDC increased in 1994 and 1993 by $11 million and $2 million, respectively, due to increased construction work in progress associated with the repowering of the Manchester Street Station (see "Liquidity and capital resources" section). Oil and gas operations New England Energy Incorporated (NEEI) participates in a rate-regulated domestic oil and gas exploration, development, and production program consisting of prospects acquired prior to December 31, 1983. NEEI is not acquiring any new prospects. Due to precipitate declines in oil and gas prices, NEEI has incurred operating losses since 1986, and expects to incur substantial additional losses in the future. These losses are being passed on to NEP under an intercompany pricing policy approved by the Securities and Exchange Commission. NEP is allowed to recover these losses from its customers under NEP's 1988 FERC rate settlement, which covered all costs incurred by or resulting from commitments made by NEEI through March 1, 1988. Other subsequent costs incurred by NEEI are subject to normal regulatory review. Hazardous waste The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. NEES subsidiaries currently have in place an environmental audit program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. NEES and/or its subsidiaries have been named as a potentially responsible party (PRP) by either the U.S. Environmental Protection Agency (EPA) or the Massachusetts Department of Environmental Protection for 22 sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against NEES and certain subsidiaries regarding hazardous waste cleanup. The most prevalent types of hazardous waste sites with which NEES and its subsidiaries have been associated are manufactured gas locations. (Until the early 1970s, NEES was a combined electric and gas holding company system.) NEES is aware of approximately 40 such locations (including seven of the 22 locations for which NEES companies are PRPs) mostly located in Massachusetts. NEES and its subsidiaries are currently aware of other sites, and may in the future become aware of additional sites, that they may be held responsible for remediating. NEES has been notified by the EPA that it is one of several PRPs for cleanup of the Pine Street Canal Superfund site in Burlington, Vermont, at which coal tar and other materials were deposited. Between 1931 and 1951, NEES and its predecessor owned all of the common stock of Green Mountain Power Corporation (GMP). Prior to, during, and after that time, gas was manufactured at the Pine Street Canal site by GMP. In 1989, NEES was one of 14 parties required to pay the EPA's past response costs related to this site. NEES remains a PRP for ongoing and future response costs. In November 1992, the EPA proposed a cleanup plan estimated by the EPA to cost $50 million. In June 1993, the EPA withdrew this cleanup plan in response to public concern about the plan and its cost. It is uncertain at this time what the cost of any ultimate cleanup plan will be or what NEES's share of such cost will be. In 1993, the MDPU approved a rate agreement filed by Massachusetts Electric (see "Retail rate activity" section) that allows for remediation costs of former manufactured gas sites and certain other hazardous waste sites located in Massachusetts to be met from a non-rate recoverable interest-bearing fund of $30 million established on Massachusetts Electric's books. Rate recoverable contributions of $3 million, adjusted for inflation, are added to the fund annually in accordance with the agreement. Any shortfalls in the fund would be paid by Massachusetts Electric and be recovered through rates over seven years. [GRAPH APPEARS HERE] [GRAPH APPEARS HERE] Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by NEES or its subsidiaries. Where appropriate, the NEES companies intend to seek recovery from their insurers and from other PRPs, but it is uncertain whether and to what extent such efforts would be successful. At December 31, 1994, NEES had total reserves for environmental response costs of $45 million and a related regulatory asset of $13 million. NEES believes that hazardous waste liabilities for all sites of which it is aware, and which are not covered by a rate agreement, will not be material to its financial position. Electric and magnetic fields (EMF) In recent years, concerns have been raised about whether EMF, which occur near transmission and distribution lines as well as near household wiring and appliances, cause or contribute to adverse health effects. Numerous studies on the effects of these fields, some of them sponsored by electric utilities (including NEES companies), have been conducted and are continuing. Some of the studies have suggested associations between certain EMF and health effects, including various types of cancer, while other studies have not substantiated such associations. It is impossible to predict the ultimate impact on NEES subsidiaries and the electric utility industry if further investigations were to demonstrate that the present electricity delivery system is contributing to increased risk of cancer or other health problems. Many utilities, including the NEES companies, have been contacted by customers regarding a potential relationship between EMF and adverse health effects. To date, no court in the United States has ruled that EMF from electrical facilities cause adverse health effects and no utility has been found liable for personal injuries alleged to have been caused by EMF. In any event, the NEES companies believe that they currently have adequate insurance coverage for personal injury claims. Several state courts have recognized a cause of action for damage to property values in transmission line condemnation cases based on the fear that power lines cause cancer. It is difficult to predict what the impact on the NEES companies would be if this cause of action is recognized in the states in which NEES companies operate and in contexts other than condemnation cases. Bills have been introduced unsuccessfully in the past in the Rhode Island legislature to require that transmission lines be placed underground. Legislation has been introduced in Massachusetts that, if passed, would require state agencies to study existing EMF-related research and make recommendations for further legislation. Clean air requirements Approximately 45 percent of NEP's electricity is produced at eight older thermal generating units in Massachusetts. Six are fueled by coal, one by oil, and one by oil and gas. The federal Clean Air Act requires significant reduction in utility sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions that result from burning fossil fuels by the year 2000 to reduce acid rain and ground-level ozone (smog). NEP is reducing SO2 emissions under Phase 1 of the federal acid rain program that became effective in 1995. NEP is also subject to Massachusetts SO2 and NOx reduction regulations taking effect in 1995. The SO2 and NOx reductions that are being made to meet 1995 Phase 1 requirements have resulted in one-time operation and maintenance costs of $16 million and capital costs of $88 million through December 31, 1994. Additional expenditures in 1995 are expected to be less than $10 million and $30 million, respectively. Depending on fuel prices, NEP also expects to incur up to $5 million annually in increased costs to purchase cleaner fuels to meet SO2 emission reduction requirements. All eight of NEP's thermal units will be subject to Phase 2 of the federal and state acid rain regulations that become effective in 2000. NEP believes that the SO2 controls already installed for the 1995 requirements will satisfy the Phase 2 acid rain regulations. In connection with the federal ozone emission requirements, state environmental agencies in ozone non-attainment areas are developing a second phase of NOx reduction regulations that would have to be fully implemented by NEP no later than 1999. While the exact costs are not known, NEP estimates that the cost of implementing these regulations would not jeopardize continued operation of NEP's units. The generation of electricity from fossil fuel also emits trace amounts of certain hazardous air pollutants and fine particulates. An EPA study of utility hazardous air pollutant emissions will be completed in 1995. The study's conclusions could lead to new emission standards requiring costly controls or fuel restrictions on NEP plants. At this time, NEES and its subsidiaries cannot estimate the impact the findings of this research might have on NEP's operations. [GRAPH APPEARS HERE] Purchased power contract dispute In October 1994, NEP was sued by Milford Power Limited Partnership (MPLP), a venture of Enron Corporation and Jones Capital that owns a 149 megawatt (MW) gas-fired power plant in Milford, Massachusetts. NEP purchases 56 percent of the power output of the facility under a long-term contract with MPLP. The suit alleges that NEP has engaged in a scheme to cause MPLP and its power plant to fail and has prevented MPLP from finding a long-term buyer for the remainder of the facility's output. The complaint includes allegations that NEP has violated the Federal Racketeer Influenced and Corrupt Organizations Act, engaged in unfair or deceptive acts in trade or commerce, and breached contracts. MPLP seeks compensatory damages in an unspecified amount, as well as treble damages. NEP believes that the allegations of wrongdoing are without merit. NEP has filed counterclaims and crossclaims against MPLP, Enron Corporation, and Jones Capital, seeking monetary damages and termination of the purchased power contract. MPLP also intervened in NEP's rate filing (see "Wholesale rate activity" section). Competitive conditions The electric utility business is being subjected to increasing competitive pressures, stemming from a combination of trends, including increasing electric rates, improved technologies, and new regulations and legislation intended to foster competition. To date, this competition has been most prominent in the bulk power market in which non-utility generating sources have noticeably increased their market share. For example, since non-utilities were allowed to enter the wholesale generation market, two-thirds of NEP's new generating capability has come from independent generating sources and Hydro-Quebec. Electric utilities are also facing increased competition in the retail market. Currently, retail competition includes competition with alternative fuel suppliers (including natural gas companies) for heating and cooling, competition with customer-owned generation to displace purchases from electric utilities, and direct competition among electric utilities to attract major new facilities to their service territories. Electric utilities including the NEES companies are under increasing pressure from large commercial and industrial customers to discount rates or face the possibility that such customers might relocate or seek alternate suppliers. Across the country, including the states serviced by the NEES companies, there have been an increasing number of proposals to allow retail customers to choose their electricity supplier, with utilities required to deliver that electricity over their transmission and distribution systems. In Massachusetts, the Massachusetts Division of Energy Resources (DOER) proposed in January 1995 that the MDPU modify its regulations to allow retail utility customers to choose a supplier and bid for access to the local utility's transmission and distribution systems in situations where new generating capacity is needed. The NEES companies have indicated their support for the DOER proposal. Also in Massachusetts, the MDPU initiated a proceeding in February 1995 regarding electric industry regulation and structure. In Rhode Island, the RIPUC has convened a task force of utilities, commercial and industrial customers, regulators, and other interested parties to prepare a report by May 1995 regarding restructuring the industry. In New Hampshire, the New Hampshire Public Utilities Commission is considering the proposal of a new company to sell electricity at retail to large customers in New Hampshire. The impact of increased customer choice on the financial condition of utilities is uncertain. In recent years, substantial surplus generating capacity in the Northeast has resulted in the sale of bulk power by utilities to other utilities at prices substantially below the total costs of owning and operating, or contracting for, such generating capacity. Should retail customers gain access to the bulk power market, particularly while surplus capacity exists, it is unlikely that utilities would be able to charge power prices which fully cover their costs. Such unrecovered costs, which could be substantial, have been referred to by the industry as stranded costs. [GRAPH APPEARS HERE] Whether and to what extent utilities should be able to recover stranded costs resulting from increased customer choice has been the subject of much debate. In 1994, the FERC issued a notice of proposed rule-making on the recovery of stranded costs. The NEES companies and other utilities have taken the position that when a regulatory body changes policies which govern customer choice and the resultant rates paid by customers, utilities must be compensated for commitments made under the former policies. Furthermore, the utility industry believes that recovery of stranded costs is necessary to promote efficient competition among market participants. Previously, the FERC ruled in 1992, in a proceeding not involving NEES subsidiaries, that a utility may recover such stranded costs from a departing wholesale requirements customer. On appeal, the United States Court of Appeals for the District of Columbia Circuit has questioned whether allowing utilities to recover stranded costs is anti-competitive and the Court remanded the case back to the FERC for further proceedings and development of the competitive issues. In addition to the arguments described above, the NEES companies have taken the position that, because utility transmission and distribution assets have a replacement value in excess of their historic costs (on which utility rates are set), utilities should have the ability to recover stranded generation-related costs by realizing the higher value of transmission and distribution assets. The NEES companies have stated their willingness, in order to assure stranded cost recovery and promote increased competition, to consider divesting their transmission system, either through sale or spinoff. The NEES companies are actively responding to current and anticipated competitive pressures in a variety of ways, including cost control and a 1993 corporate reorganization into separate retail and wholesale business units. The wholesale business unit has responded to increased competition by freezing base rates until at least 1997 (base rates were last raised in March 1992), terminating certain purchased power and gas pipeline contracts, shutting down uneconomic generating stations, and accelerating the recovery of uneconomic assets and other deferred costs. In addition, NEP's wholesale tariff requires its wholesale customers, including NEES's retail subsidiaries, to provide seven years notice before they may terminate the tariff. The retail business unit's response to competition includes the EnergyFIT program which offers comprehensive value-added services for large business customers, intensified business development efforts, including economic development rates and service packages to encourage businesses to locate in the retail companies' service territories, and development of new pricing and service options for customers. Additionally, more than 80 percent of the NEES companies' large commercial and industrial customers have signed service extension discount (SED)contracts providing for discounts and requiring three to five years notice before they may change electricity suppliers (see "Retail rate activity" section). As part of their long-term planning process, the NEES companies are from time to time evaluating other strategies, such as business combinations and other forms of restructuring, to better respond to the changing competitive environment. Electric utility rates are generally based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. These accounting rules require regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the income statement impact of certain costs that are expected to be recovered in future rates. The effects of competition could ultimately cause the operations of the NEES companies, or a portion thereof, to cease meeting the criteria for application of these accounting rules. In such an event, accounting standards applicable to enterprises in general would apply and immediate write-off of any previously deferred costs (regulatory assets) would be necessary in the year in which these criteria were no longer applicable. In addition, if, because of competition, utilities are unable to recover all of their costs in rates, it may be necessary to write off those costs that are not recoverable. [GRAPH APPEARS HERE] Liquidity and capital resources Capital requirements for 1994 and projections for 1995 are shown below: Year ended December 31 (millions of dollars)1994 1995 ---- ---- Cash expenditures for utility plant: Manchester Street repowering project $176 $125 All other 262 200 Oil and gas exploration and development 28 15 ---- ---- Total capital expenditures $466 $340 Maturing debt and prepayment requirements35 66 ---- ---- Total capital requirements $501 $406 Cash from utility operations after payment of dividends $285 $265 Cash from oil and gas operations 57 50 ---- ---- Total cash from operations after the payment of dividends $342 $315 The funds necessary for utility plant expenditures in 1994 were primarily provided by net cash from operating activities, after the payment of dividends, and the proceeds of short-term and long-term borrowings. The financing activities of the NEES subsidiaries for 1994 are summarized as follows: Long-term debt ---------------------------- (millions of dollars) Issues Retirements ------ ----------- NEP $28 Massachusetts Electric 36 Narragansett 33 Granite State Electric Company $ 1 Hydro-Transmission Companies 12 NEEI 22 ---- ---- $97 $35 Interest rates on the long-term debt issues shown above range from 6.91 percent to 8.85 percent. Internally generated funds are expected to meet approximately 75 percent of the 1995 capital expenditure requirements for utility plant. NEP and the retail subsidiaries have issued $56 million of long-term debt to date in 1995 at interest rates ranging from 7.79 percent to 8.45 percent. These companies plan to issue an additional $120 million of long-term debt later in 1995 to meet maturing long-term debt obligations, reduce short-term debt and fund capital expenditures. Net cash from operating activities provided all of the funds necessary for oil and gas expenditures. NEEI's 1994 oil and gas exploration and development costs included $10 million of capitalized interest costs. The NEES subsidiaries' major construction project is the repowering of Manchester Street Station, a 140 MW electric generating station in Providence, Rhode Island. Repowering will more than triple the power generation capacity of Manchester Street Station and substantially increase the plant's thermal efficiency. NEP owns a 90 percent interest and Narragansett owns a 10 percent interest in the Manchester Street Station. The total cost for the generating station, scheduled to be placed in service in late 1995, is estimated to be approximately $520 million including AFDC. At December 31, 1994, $298 million, including AFDC, had been spent on the generating station. In addition, related transmission improvements were placed in service in September 1994 at a cost of approximately $60 million. At December 31, 1994, NEES and its consolidated subsidiaries had lines of credit and standby bond purchase facilities with banks totaling $663 million. These lines and facilities were used at December 31, 1994 for $2 million of direct borrowings, and for liquidity support for $232 million of commercial paper borrowings and $342 million of NEP mortgage bonds in tax-exempt commercial paper mode. Fees are paid on the lines and facilities in lieu of compensating balances. New England Electric System and Subsidiaries Selected Financial Data Year ended December 31 (millions of dollars, except per share data)
1994 1993 1992 1991 1990 ---- ---- ---- ---- ---- Operating revenue: Electric sales (excluding fuel cost recovery)$1,518$1,488 $1,424 $1,358 $1,282 Fuel cost recovery 568 582 597 585 523 Other utility revenue 117 117 118 114 65 Oil and gas sales 40 47 43 37 39 ------ ------ ------ ------ ------ Total operating revenue$2,243 $2,234 $2,182 $2,094 $1,909 Net income $ 199 $ 190 $ 185 $ 180 $ 262* Average common shares outstanding (000's) 64,970 64,970 64,970 64,917 63,818 Per share data: Net income $3.07 $ 2.93 $ 2.85 $ 2.77 $ 4.11* Dividends declared $2.285 $ 2.22 $ 2.14 $ 2.07 $ 2.04 Return on average common equity 12.73% 12.64% 12.58% 12.64% 20.52%* Total assets $5,085 $4,796 $4,585 $4,450 $4,408 Capitalization: Common share equity $1,581 $1,530 $1,487 $1,441 $1,380 Minority interests 55 56 61 63 62 Cumulative preferred stock 147 147 162 162 162 Long-term debt 1,520 1,512 1,533 1,548 1,680 ------ ------ ------ ------ ------ Total capitalization $3,303 $3,245 $3,243 $3,214 $3,284 Sales billed to ultimate customers (millions of KWH)21,155 20,832 20,554 20,470 20,727 Cost per KWH to ultimate customers (cents) 9.29 9.50 9.43 8.99 8.27 System maximum demand (MW)4,385 4,081 3,964 4,250 4,059 Electric capability (MW net)-year end 5,533 5,362 5,479 5,645 5,627 Number of employees 4,990 4,969 5,415 5,533 5,666 Number of customers 1,300,1981,288,1841,277,281 1,257,2131,256,656 *1990 includes $1.80 per share, resulting from a rate settlement related to Seabrook 1.
New England Electric System and Subsidiaries Statements of Consolidated Income Year ended December 31 (thousands of dollars, except per share data) 1994 1993 1992 ---------- ---------- ---------- Operating revenue: $2,243,029 $2,233,978 $2,181,676 Operating expenses: Fuel for generation 220,956 227,182 237,161 Purchased electric energy514,143 527,307 525,655 Other operation 494,741 492,079 423,330 Maintenance 161,473 146,219 162,974 Depreciation and amortization301,123 296,631 302,217 Taxes, other than income taxes125,840120,493 114,027 Income taxes 128,257 121,124 110,761 --------- --------- --------- Total operating expenses1,946,533 1,931,035 1,876,125 Operating income 296,496 302,943 305,551 Other income: Allowance for equity funds used during construction 10,169 3,795 2,732 Equity in income of generating companies 9,758 11,016 13,052 Other income (expense)-net(3,856) (1,154) 936 --------- ---------- --------- Operating and other income312,567 316,600 322,271 Interest: Interest on long-term debt93,500 100,777 114,182 Other interest 11,298 9,809 5,420 Allowance for borrowed funds used during construction (7,793) (2,816) (2,204) --------- --------- ---------- Total interest 97,005 107,770 117,398 Income after interest 215,562 208,830 204,873 Preferred dividends of subsidiaries 8,697 10,585 10,572 Minority interests 7,439 8,022 9,264 --------- --------- --------- Net income $199,426 $190,223 $185,037 Common shares outstanding64,969,65264,969,65264,969,652 Per share data: Net income $ 3.07 $ 2.93 $ 2.85 Dividends declared $ 2.285 $ 2.22 $ 2.14 Statements of Consolidated Retained Earnings Year ended December 31 (thousands of dollars) 1994 1993 1992 ---------- ---------- ---------- Retained earnings at beginning of year $ 728,075 $ 684,132 $ 638,130 Net income 199,426 190,223 185,037 Dividends declared on common shares (148,456) (144,233) (139,035) Premium on redemption of preferred stock of subsidiaries (2,047) ---------- --------- --------- Retained earnings at end of year $ 779,045 $ 728,075 $ 684,132 The accompanying notes are an integral part of these consolidated financial statements. New England Electric System and Subsidiaries Consolidated Balance Sheets At December 31 (thousands of dollars) 1994 1993 ---------- ---------- Assets Utility plant, at original cost $4,914,807 $4,661,612 Less accumulated provisions for depreciation and amortization 1,610,378 1,511,271 ---------- ---------- 3,304,429 3,150,341 Net investment in Seabrook 1 under rate settlement (Note C) 38,283 103,344 Construction work in progress 374,009 228,816 ---------- ---------- Net utility plant 3,716,721 3,482,501 Oil and gas properties, at full cost (Note A)1,248,3431,220,110 Less accumulated provision for amortization 964,069 884,837 ---------- ---------- Net oil and gas properties 284,274 335,273 Investments: Nuclear power companies, at equity (Note D) 46,349 46,342 Other subsidiaries, at equity 42,195 44,676 Other investments 50,895 28,836 ---------- ---------- Total investments 139,439 119,854 Current assets: Cash 3,047 2,876 Accounts receivable, less reserves of $15,095 and $14,551 295,627 275,020 Unbilled revenues (Note A) 55,900 43,400 Fuel, materials, and supplies, at average cost94,431 74,314 Prepaid and other current assets 76,718 69,004 ---------- ---------- Total current assets 525,723 464,614 Accrued Yankee Atomic costs (Note D) 122,452 103,501 Deferred charges and other assets (Note A) 296,232 290,135 ---------- ---------- $5,084,841 $4,795,878 ========== ========== Capitalization and liabilities Capitalization (see accompanying statements): Common share equity $1,580,838 $1,529,868 Minority interests in consolidated subsidiaries55,066 55,855 Cumulative preferred stock of subsidiaries 147,016 147,528 Long-term debt 1,520,488 1,511,589 ---------- ---------- Total capitalization 3,303,408 3,244,840 Current liabilities: Long-term debt due within one year 65,920 12,920 Short-term debt 233,970 71,775 Accounts payable 168,937 128,342 Accrued taxes 11,002 10,332 Accrued interest 25,193 23,278 Dividends payable 37,154 36,950 Other current liabilities (Note A) 93,251 153,812 ---------- ---------- Total current liabilities 635,427 437,409 Deferred federal and state income taxes 751,855 705,026 Unamortized investment tax credits 94,930 99,355 Accrued Yankee Atomic costs (Note D) 122,452 103,501 Other reserves and deferred credits 176,769 205,747 Commitments and contingencies (Note E) ---------- ---------- $5,084,841 $4,795,878 ========== ========== The accompanying notes are an integral part of these consolidated financial statements. New England Electric System and Subsidiaries Consolidated Statements of Cash Flows Year ended December 31 (thousands of dollars) 1994 1993 1992 --------- --------- --------- Operating activities Net income $ 199,426 $ 190,223 $ 185,037 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 305,908 300,444 305,046 Deferred income taxes and investment tax credits-net 41,741 4,105 11,163 Allowance for funds used during construction (17,962) (6,611) (4,936) Amortization of unbilled revenues(38,458) (2,700) Minority interests 7,439 8,022 9,264 Early retirement program 23,922 Decrease (increase) in accounts receivable, net and unbilled revenues (33,107) (27,503) (27,157) Decrease (increase) in fuel, materials, and supplies (20,117) 13,786 (8,590) Decrease (increase) in prepaid and other current assets (7,714) 5,904 (64,858) Increase (decrease) in accounts payable 40,595 (42,967) 34,623 Increase (decrease) in other current liabilities (25,676) 64,658 (2,447) Other, net (34,109) (32,632) (2,146) --------- --------- -------- Net cash provided by operating activities $ 417,966 $ 498,651 $ 434,999 Investing activities Plant expenditures, excluding allowance for funds used during construction $(438,016) $(304,659) $(241,872) Oil and gas exploration and development (28,233) (18,965) (21,262) Other investing activities (18,830) (107) 2,388 --------- --------- --------- Net cash used in investing activities $(485,079) $(323,731) $(260,746) Financing activities Dividends paid to minority interests$ (8,416)$ (10,622)$ (15,939) Dividends paid on NEES common shares(148,063)(142,352)(140,174) Short-term debt 162,195 29,525 42,250 Long-term debt-issues 97,000 372,500 477,500 Long-term debt-retirements (34,920) (395,820) (585,120) Preferred stock-issues 55,000 Preferred stock-retirements (512) (70,000) Premium on reacquisition of long-term debt (10,996) (16,135) Premium on redemption of preferred stock (2,047) --------- --------- --------- Net cash provided by (used in) financing activities $ 67,284 $(174,812) $(237,618) Net increase (decrease) in cash and cash equivalents $ 171 $ 108 $ (63,365) Cash and cash equivalents at beginning of year 2,876 2,768 66,133 --------- --------- --------- Cash and cash equivalents at end of year $ 3,047 $ 2,876 $ 2,768 Supplementary information Interest paid less amounts capitalized$ 90,500$ 97,518$ 119,146 Federal and state income taxes paid$ 114,597$ 124,853$ 99,935 Dividends received from investments at equity $ 15,350 $ 14,404 $ 18,405 The accompanying notes are an integral part of these consolidated financial statements. New England Electric System and Subsidiaries Consolidated Statements of Capitalization At December 31 (thousands of dollars)
1994 1993 ---------- ---------- Common share equity Common shares, par value $1 per share Authorized-150,000,000 shares Outstanding-64,969,652 shares $ 64,970 $ 64,970 Paid-in capital 736,823 736,823 Retained earnings 779,045 728,075 ---------- ---------- Total common share equity $1,580,838 $1,529,868
Cumulative preferred stock of Shares outstanding subsidiaries 1994 1993 1994 1993 --------- --------- -------- -------- $100 Par value- 4.44% to 4.76% 430,140 430,140 $ 43,014 $ 43,014 6.00% to 7.24% 525,020 530,140 52,502 53,014 $50 Par value- 4.50% to 6.95% 730,000 730,000 36,500 36,500 $25 Par value- 6.84% 600,000 600,000 15,000 15,000 --------- --------- -------- -------- Total cumulative preferred stock of subsidiaries (annual dividend requirement of $8,690 for 1994 and $8,720 for 1993) 2,285,160 2,290,280 $147,016 $147,528
Long-term debt (Note H) Maturity Rate 1994 1993 ------------------------------------- -------- Mortgage bonds* 1995 through 19994.730%-8.280%$ 203,500$ 187,500 2000 through 20046.240%-8.520%187,500 152,500 2005 through 20146.110%-6.660%35,000 35,000 2015 through 20247.050%-9.125%422,550 376,550 2018 through 2022 Variable342,000 342,000 Notes Granite State Electric Company1996 through 20237.370%-12.550%14,40015,800 New England Energy Incorporated 1998 Variable216,000238,000 Hydro-Transmission Companies2001 through 20158.820%-9.410%171,050 182,570 Unamortized discounts and premiums, net (5,592) (5,411) ------------------- Total long-term debt 1,586,4081,524,509 Long-term debt due in one year (65,920) (12,920) ------------------- $1,520,488$1,511,589 *Includes $382,350 issued to secure tax-exempt pollution control and solid waste disposal revenue bonds issued by state agencies on behalf of New England Power Company. The accompanying notes are an integral part of these consolidated financial statements.
New England Electric System and Subsidiaries Notes to Consolidated Financial Statements Note A - Significant accounting policies 1.Basis of consolidation and system of accounts The consolidated financial statements include the accounts of New England Electric System (NEES) and all subsidiaries except New England Electric Transmission Corporation, which is recorded at equity. Presentation of this subsidiary on the equity basis is not material to the consolidated financial statements. New England Power Company (NEP) has a minority interest in four regional nuclear generating companies (Yankees). Narragansett Energy Resources Company (Resources) has a 20 percent general partnership interest in the Ocean State Power (OSP) generating facility. NEP and Resources account for these ownership interests on the equity method. NEES owns 50.4 percent of the outstanding common stock of both New England Hydro-Transmission Electric Company, Inc. and New England Hydro-Transmission Corporation (Hydro-Transmission companies). The consolidated financial statements include 100 percent of the assets, liabilities, and earnings of the Hydro-Transmission companies. Since NEES is the majority stockholder in these companies, the ownership interests of the other stockholders are called minority interests and have been separately disclosed on the NEES consolidated income statements and balance sheets. The "Minority interests" line on the statements of consolidated income includes the minority interests' portion of the net earnings of the Hydro-Transmission companies. NEP is also a 12 percent and 10 percent joint owner, respectively, of the Millstone 3 and Seabrook 1 nuclear generating units, each 1,150 megawatts (MW). NEP's net investment in Millstone 3, included in net utility plant, is approximately $400 million. (See Note C for a discussion of Seabrook 1.) NEP's share of the related expenses for these units is included in "Operating expenses". The accounts of NEES and its utility subsidiaries are maintained in accordance with the Uniform System of Accounts prescribed by regulatory bodies having jurisdiction. All significant intercompany transactions between consolidated subsidiaries have been eliminated. 2.Electric sales revenue Massachusetts Electric Company (Massachusetts Electric) and The Narragansett Electric Company (Narragansett), pursuant to rate agreements that went into effect in 1993 and 1994, respectively, began accruing revenues for electricity delivered but not yet billed. Unbilled revenues at December 31, 1994 and 1993 were $56 million and $43 million, respectively, of which, $37 million and $11 million were recognized in income in 1994 and the fourth quarter of 1993, respectively. The remainder of $8 million at December 31, 1994 has been deferred for recognition monthly through December 1995. Accrued revenues are also recorded in accordance with rate adjustment mechanisms. 3.Allowance for funds used during construction (AFDC) The utility subsidiaries capitalize AFDC as part of construction costs. AFDC represents the composite interest and equity costs of capital funds used to finance that portion of construction costs not eligible for inclusion in rate base. In 1994, an average of $30 million of construction work in progress was included in rate base, all of which was attributable to the Manchester Street Station repowering project. AFDC is capitalized in "Utility plant" with offsetting non-cash credits to "Other income" and "Interest". This method is in accordance with an established rate-making practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFDC rates were 7.6 percent, 7.4 percent, and 8.6 percent, in 1994, 1993, and 1992, respectively. 4.Depreciation and amortization The depreciation and amortization expense included in the statements of consolidated income is composed of the following: Year ended December 31 (thousands of dollars) 1994 1993 1992 ---------------- -------- Depreciation $136,746$127,428 $130,655 Nuclear decommissioning costs (Note A-5) 1,951 1,951 1,890 Amortization: Oil and gas properties (Note A-6) 79,232 90,399 99,687 Investment in Seabrook 1 nuclear unit under rate settlement (Note C) 65,061 58,437 52,443 Oil Conservation Adjustment 11,854 12,137 11,263 Property losses 6,279 6,279 6,279 ---------------- -------- Total depreciation and amortization expense$301,123$296,631$302,217 Depreciation is provided annually on a straight-line basis. The provision for depreciation as a percentage of weighted average depreciable property was 3.1 percent in 1994, 3.0 percent in 1993, and 3.2 percent in 1992. The Oil Conservation Adjustment is designed to recover expenditures for coal conversion facilities at NEP's Salem Harbor Station by 1995. At December 31, 1994, such unamortized coal conversion costs included in utility plant were $4,467,000. 5.Nuclear plant decommissioning and nuclear fuel disposal NEP is recovering its share of projected decommissioning costs for Millstone 3 and Seabrook 1 through depreciation expense. NEP records decommissioning cost expense on its books consistent with its rate recovery. In addition, NEP is paying its portion of projected decommissioning costs for all of the Yankees through purchased power expense. Such costs reflect estimates of total decommissioning costs approved by the Federal Energy Regulatory Commission (FERC). Each of the operating nuclear units in which NEP has an ownership interest has established decommissioning trust funds or escrow funds into which payments are being made to meet the projected costs of decommissioning its plant. If any of the units were shut down prior to the end of their operating licenses, the funds collected for decommissioning to that point would be insufficient. Listed below is information on each nuclear plant in which NEP has an ownership interest. (See Note D for a discussion of Yankee Atomic Nuclear Power Station decommissioning.) NEP's share of (millions of dollars) --------------------------------------------------- Estimated Ownership Decommissioning Fund License Unit Interest Cost (in 1994 $)Balances**Expiration - ---------------------------------------------------------------- Connecticut Yankee 15% 53 22 2007 Maine Yankee*** 20% 66 22 2008 Vermont Yankee 20% 66 23 2012 Millstone 3* 12% 53 11 2025 Seabrook 1* 10% 36 4 2026 *Fund balances are included in "Other investments" on the balance sheet and approximate market value. **Certain additional amounts are anticipated to be available through tax deductions. ***A Maine statute provides that if both Maine Yankee and its decommissioning trust fund have insufficient assets to pay for the plant decommissioning, the owners of Maine Yankee are jointly and severally liable for the shortfall. In accordance with its recent rate agreement which became effective in 1995, NEP is allowed to defer for later recovery any increases in decommissioning payments over the level included in rates until its next rate filing becomes effective. There is no assurance that decommissioning costs actually incurred by the Yankees, Millstone 3, or Seabrook 1 will not substantially exceed these amounts. For example, decommissioning cost estimates assume the availability of permanent repositories for both low-level and high-level nuclear waste which do not currently exist. The Nuclear Waste Policy Act of 1982 establishes that the federal government is responsible for the disposal of spent nuclear fuel. The federal government requires NEP to pay a fee based on its share of the net generation from the Millstone 3 and Seabrook 1 nuclear units. NEP is recovering this fee through its fuel clause. Similar costs are incurred by Connecticut Yankee, Maine Yankee, and Vermont Yankee. These costs are billed to NEP and recovered from customers through NEP's fuel clause. 6.Oil and gas operations New England Energy Incorporated (NEEI) participates in a rate-regulated domestic oil and gas exploration, development, and production program through a partnership with a non-affiliated oil company. This program consists of prospects acquired prior to December 31, 1983. No new prospects will be acquired under this program. However, NEEI continues to incur costs in connection with existing prospects. Savings and losses from this program are being passed on to NEP and ultimately to retail customers, under an intercompany pricing policy (Pricing Policy) approved by the Securities and Exchange Commission (SEC). NEEI has incurred operating losses since 1986 due to precipitate declines in oil and gas prices, and expects to incur substantial additional losses in the future. Such losses were $40 million, $46 million, and $55 million in 1994, 1993, and 1992, respectively. NEP's ability to pass these losses on to its customers was favorably resolved in NEP's 1988 FERC rate settlement. This settlement covered all costs incurred by or resulting from commitments made by NEEI through March 1, 1988. Other subsequent costs incurred by NEEI are subject to normal regulatory review. NEEI follows the full cost method of accounting for its oil and gas operations, under which capitalized costs (including interest paid to banks) relating to wells and leases determined to be either commercial or non-commercial are amortized using the unit of production method. The Pricing Policy has allowed NEEI to capitalize all costs incurred in connection with fuel exploration activities of its rate-regulated program, including interest paid to banks of which $10 million, $9 million, and $14 million was capitalized in 1994, 1993, and 1992, respectively. In the absence of the Pricing Policy, the SEC's full cost "ceiling test" rule requires non-rate-regulated companies to write down capitalized costs to a level which approximates the present value of their proved oil and gas reserves. Based on NEEI's 1994 average oil and gas selling prices and NEEI's proved reserves at December 31, 1994, application of the ceiling test would have resulted in a write-down of approximately $120 million after tax. 7.Cash NEES and its subsidiaries classify short-term investments with a maturity of 90 days or less as cash. Current banking arrangements do not require outstanding checks to be funded until actually presented for payment. Outstanding checks are therefore recorded in accounts payable until such time as the banks present them for payment. 8.Deferred charges and other assets The components of deferred charges and other assets are as follows: At December 31 (thousands of dollars) 1994 1993 ---------- ---------- Regulatory assets: Unamortized losses on reacquired debt $ 56,249 $ 60,333 Deferred SFAS No. 106 costs (see Note F-2)41,009 24,563 Deferred SFAS No. 109 costs (see Note B)74,423 73,760 Purchased power termination costs 29,012 28,400 Deferred gas pipeline charges (see Note E-2)37,562 13,187 Environmental response costs (see Note E-3)13,167 18,752 Deferred storm costs 10,822 14,774 Unamortized property losses 7,373 12,745 Other 5,111 11,892 -------- -------- 274,728 258,406 Other deferred charges and other assets: Intangible asset-pensions (see Note F-1) 4,749 15,103 Other 16,755 16,626 -------- -------- $296,232 $290,135 Electric utility rates are generally based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. These accounting rules require regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the income statement impact of certain costs that are expected to be recovered in future rates. The effects of competition could ultimately cause the operations of the NEES companies, or a portion thereof, to cease meeting the criteria for application of these accounting rules. In such an event, accounting standards applicable to enterprises in general would apply and immediate write-off of any previously deferred costs (regulatory assets) would be necessary in the year in which these criteria were no longer applicable. Approximately $150 million of the regulatory assets at December 31, 1994 listed above are expected to be recovered within 10 years, with the majority of the remaining balance to be recovered within the following 20 years. The only items for which the majority of the balance shown above will not be recovered within the next 10 years are the deferred SFAS No. 109 costs and the deferred gas pipeline charges. 9.Other current liabilities The components of other current liabilities are as follows: At December 31 (thousands of dollars) 1994 1993 ---------- ---------- Accrued wages and benefits $26,035 $ 39,756 Deferred unbilled revenues 8,209 32,300 Rate adjustment mechanisms 31,311 31,237 Accrued purchased power termination costs 21,900 Customer deposits 10,951 12,336 Other 16,745 16,283 ------- -------- $93,251 $153,812 Note B - Income taxes Total income taxes in the statements of consolidated income are as follows: Year ended December 31 (thousands of dollars) 1994 1993 1992 ---------------- -------- Income taxes charged to operations $128,257$121,124 $110,761 Income taxes charged to "Other income" 779 3,147 3,192 ---------------- -------- Total income taxes $129,036$124,271 $113,953 Total income taxes, as shown above, consist of the following components: Year ended December 31 (thousands of dollars) 1994 1993 1992 -------- ---------------- Current income taxes $ 87,295$120,167 $102,790 Deferred income taxes 46,166 7,756 13,475 Investment tax credits-net (4,425) (3,652) (2,312) ---------------- -------- Total income taxes $129,036$124,271 $113,953 Total income taxes, as shown above, consist of federal and state components as follows: Year ended December 31 (thousands of dollars) 1994 1993 1992 -------- ---------------- Federal income taxes $104,136$ 98,529 $ 92,647 State income taxes 24,900 25,742 21,306 ---------------- -------- Total income taxes $129,036$124,271 $113,953 Investment tax credits of subsidiaries are deferred and amortized over the estimated lives of the property giving rise to the credits. Since the Tax Reform Act of 1986 generally eliminated investment tax credits, the amounts shown above principally reflect the amortization of investment tax credits generated in prior years. With regulatory approval, the subsidiaries have adopted comprehensive interperiod tax allocation (normalization) for temporary book/tax differences. Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows: Year ended December 31 (thousands of dollars) 1994 1993 1992 -------- ---------------- Computed tax at statutory rate $118,006$113,778 $105,251 Increases (reductions) in tax resulting from: Reversal of deferred taxes recorded at a higher rate (4,230) (5,099) (7,175) Amortization of investment tax credits (5,272) (4,697) (5,384) State income tax, net of federal income tax benefit 16,185 16,732 14,062 All other differences 4,347 3,557 7,199 ---------------- -------- Total income taxes $129,036$124,271 $113,953 The Financial Accounting Standards Board established Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes" which became effective in 1993. The application of this new standard did not have a significant impact on 1993 or 1994 net income. The following table identifies the major components of total deferred income taxes: At December 31 (millions of dollars) 1994 1993 ---------- ---------- Deferred tax asset: Plant related $ 107 $ 99 Investment tax credits 38 40 All other 108 129 ------ ------ 253 268 Deferred tax liability: Plant related (777) (758) Equity AFDC (52) (57) All other (176) (158) ------ ------ (1,005) (973) ------ ------ Net deferred tax liability $ (752) $ (705) There were no valuation allowances for deferred tax assets deemed necessary. The deferred taxes resulting from timing differences which appear on the income statement in 1992 (prior to the adoption of SFAS No. 109 in 1993) primarily include deferred income taxes of $29 million related to utility plant and $17 million in connection with postretirement benefits, partially offset by deferred tax credits of $31 million associated with oil and gas operations. Federal income tax returns for NEES and its subsidiaries have been examined and reported on by the Internal Revenue Service through 1991. Note C - Seabrook Nuclear Unit 1 (Seabrook 1) NEP owns approximately 10 percent of Seabrook 1, a 1,150 MW nuclear generating unit that entered commercial service in 1990. NEP's rate recovery of its investment in Seabrook 1 was resolved through two separate rate settlement agreements. NEP's pre-1988 investment was being recovered in rates over a period of seven and one-half years ending in mid-1995. Under NEP's rate agreement, that was recently approved by the FERC, approximately $15 million of the $38 million in Seabrook 1 costs due to be recovered in 1995 pursuant to a 1988 settlement agreement will be deferred and recovered in 1996. This investment, net of amortization, is shown on a separate line on the consolidated balance sheets. NEP's net investment in Seabrook 1 since January 1, 1988, which amounts to approximately $43 million at December 31, 1994, is included under the caption "Utility plant" on the consolidated balance sheet and is being recovered over 37 years. Note D - Yankee Atomic Nuclear Power Station NEP has a 30 percent ownership interest in Yankee Atomic Electric Company (Yankee Atomic), which owns a 185 MW nuclear generating station in Rowe, Massachusetts. The station began commercial service in 1960. At December 31, 1994, NEP's investment in Yankee Atomic was approximately $7 million. In February 1992, the Yankee Atomic board of directors decided to permanently cease power operation of, and in time decommission, the facility. In March 1993, the FERC approved a settlement agreement that allows Yankee Atomic to recover all but $3 million of its approximately $50 million remaining investment in the plant over the period extending to July 2000, when the plant's Nuclear Regulatory Commission (NRC) operating license would have expired. Yankee Atomic recorded the $3 million before-tax write-down in 1992. The settlement agreement also allows Yankee Atomic to earn a return on the unrecovered balance during the recovery period and to recover other costs, including an increased level of decommissioning costs, over this same period. Decommissioning cost recovery increased from $6 million per year to $27 million per year for the period 1993 to 1995. In the fourth quarter of 1994, Yankee announced a new decommissioning cost estimate that, subject to approval by the FERC, would increase billings to NEP by an additional $11 million per year through July 2000. NEP has recorded an estimate of its entire future payment obligations to Yankee Atomic as a liability on its balance sheet and an offsetting regulatory asset reflecting its expected future rate recovery of such costs. This liability and related regulatory asset amounted to approximately $122 million each at December 31, 1994, and are included on separate lines in the consolidated balance sheet. Note E - Commitments and contingencies 1. Plant expenditures The NEES subsidiaries' utility plant expenditures are estimated to be $325 million in 1995. At December 31, 1994, substantial commitments had been made relative to future planned expenditures. 2. Natural gas pipeline capacity In connection with NEP's efforts to reduce sulfur dioxide emissions and repower generating units, NEP has signed several contracts for natural gas pipeline capacity and gas supply. These agreements require minimum fixed payments. NEP's minimum net payments are currently estimated to be approximately $65 million in 1995 and $70 million per year during 1996 to 1999. As part of a rate settlement, NEP is recovering 50 percent of the fixed pipeline capacity payments through its current fuel clause and deferring the recovery of the remaining 50 percent until the Manchester Street repowering project is completed. NEP has deferred payments of approximately $38 million as of December 31, 1994 (see Note A-8). NEP has been using a portion of this capacity to sell natural gas, the proceeds from which have been passed to customers through NEP's fuel clause. 3. Hazardous waste The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. NEES subsidiaries currently have in place an environmental audit program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. NEES and/or its subsidiaries have been named as a potentially responsible party (PRP) by either the U.S. Environmental Protection Agency (EPA) or the Massachusetts Department of Environmental Protection for 22 sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against NEES and certain subsidiaries regarding hazardous waste cleanup. The most prevalent types of hazardous waste sites with which NEES and its subsidiaries have been associated are manufactured gas locations. (Until the early 1970s, NEES was a combined electric and gas holding company system.) NEES is aware of approximately 40 such locations (including seven of the 22 locations for which NEES companies are PRPs) mostly located in Massachusetts. NEES and its subsidiaries are currently aware of other sites, and may in the future become aware of additional sites, that they may be held responsible for remediating. NEES has been notified by the EPA that it is one of several PRPs for cleanup of the Pine Street Canal Superfund site in Burlington, Vermont, at which coal tar and other materials were deposited. Between 1931 and 1951, NEES and its predecessor owned all of the common stock of Green Mountain Power Corporation (GMP). Prior to, during, and after that time, gas was manufactured at the Pine Street Canal site by GMP. In 1989, NEES was one of 14 parties required to pay the EPA's past response costs related to this site. NEES remains a PRP for ongoing and future response costs. In November 1992, the EPA proposed a cleanup plan estimated by the EPA to cost $50 million. In June 1993, the EPA withdrew this cleanup plan in response to public concern about the plan and its cost. It is uncertain at this time what the cost of any ultimate cleanup plan will be or what NEES's share of such costs will be. In 1993, the Massachusetts Department of Public Utilities approved a rate agreement filed by Massachusetts Electric that allows for remediation costs of former manufactured gas sites and certain other hazardous waste sites located in Massachusetts to be met from a non-rate recoverable interest-bearing fund of $30 million established on Massachusetts Electric's books. Rate recoverable contributions of $3 million, adjusted for inflation, are added to the fund annually in accordance with the agreement. Any shortfalls in the fund would be paid by Massachusetts Electric and be recovered through rates over seven years. The resolution of the issue of rate recovery resulted in a one-time increase to fourth quarter 1993 earnings of $11 million due to the reversal of a portion of previously established hazardous waste reserves. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by NEES or its subsidiaries. Where appropriate, the NEES companies intend to seek recovery from their insurers and from other PRPs, but it is uncertain whether and to what extent such efforts would be successful. At December 31, 1994, NEES had total reserves for environmental response costs of $45 million and a related regulatory asset of $13 million. NEES believes that hazardous waste liabilities for all sites of which it is aware, and which are not covered by a rate agreement, will not be material to its financial position. 4. Nuclear insurance The Price-Anderson Act limits the amount of liability claims that would have to be paid in the event of a single incident at a nuclear plant to $8.9 billion (based upon 110 licensed reactors). The maximum amount of commercially available insurance coverage to pay such claims is only $200 million. The remaining $8.7 billion would be provided by an assessment of up to $79.3 million per incident levied on each of the nuclear units in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. The maximum assessment, which was most recently calculated in 1993, is to be adjusted at least every five years to reflect inflationary changes. NEP's current interest in the Yankees (excluding Yankee Atomic), Millstone 3, and Seabrook 1 would subject NEP to a $58.0 million maximum assessment per incident. NEP's payment of any such assessment would be limited to a maximum of $7.3 million per incident per year. As a result of the permanent cessation of power operation of the Yankee Atomic plant, Yankee Atomic has received from the NRC a partial exemption from obligations under the Price-Anderson Act. However, Yankee Atomic must continue to maintain $100 million of commercially available nuclear insurance coverage. Each of the nuclear units in which NEP has an ownership interest also carries nuclear insurance to cover the costs of property damage, decontamination or premature decommissioning and workers' claims resulting from a nuclear incident. These policies may require additional premium assessments if losses relating to nuclear incidents at units covered by this insurance occurring in a prior six year period exceed the accumulated funds available. NEP's maximum potential exposure for these assessments, either directly, or indirectly through purchased power payments to the Yankees, is approximately $17 million per year. 5. Long-term contracts for the purchase of electricity NEP purchases a portion of its electricity requirements pursuant to long-term contracts with owners of various generating units. These contracts expire in various years from 1995 to 2029. Certain of these contracts require NEP to make minimum fixed payments, even when the supplier is unable to deliver power, to cover NEP's proportionate share of the capital and fixed operating costs of these generating units. The majority of the payments under these contracts are to the Yankees (excluding Yankee Atomic-see Note D) and OSP, entities in which NEES subsidiaries hold ownership interests. The fixed portion of payments under these contracts totaled $190 million in 1994 and $220 million in 1993 and 1992. These contracts have minimum fixed payment requirements of $215 million in 1995, $195 million in 1996, $190 million in 1997 and 1998, $185 million in 1999, and approximately $2 billion thereafter. NEP's other contracts, principally with non-utility generators, require NEP to make payments only if power supply capacity and energy are deliverable from such suppliers. NEP's payments under these contracts amounted to $210 million in 1994 and 1993 and $200 million in 1992. 6. Purchased power contract dispute In October 1994, NEP was sued by Milford Power Limited Partnership (MPLP), a venture of Enron Corporation and Jones Capital that owns a 149 MW gas-fired power plant in Milford, Massachusetts. NEP purchases 56 percent of the power output of the facility under a long-term contract with MPLP. The suit alleges that NEP has engaged in a scheme to cause MPLP and its power plant to fail and has prevented MPLP from finding a long-term buyer for the remainder of the facility's output. The complaint includes allegations that NEP has violated the Federal Racketeer Influenced and Corrupt Organizations Act, engaged in unfair or deceptive acts in trade or commerce, and breached contracts. MPLP seeks compensatory damages in an unspecified amount, as well as treble damages. NEP believes that the allegations of wrongdoing are without merit. NEP has filed counterclaims and crossclaims against MPLP, Enron Corporation, and Jones Capital, seeking monetary damages and termination of the purchased power contract. MPLP also intervened in a recent NEP rate filing. Note F - Employee benefits 1.Pension plans The NEES companies' retirement plans are noncontributory defined-benefit plans covering substantially all employees. The plans provide pension benefits based on the employee's compensation during the five years before retirement. The NEES companies' funding policy is to contribute each year, the net periodic pension cost for that year. However, the contribution for any year will not be less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. Net pension cost for 1994, 1993, and 1992 included the following components: Year ended December 31 (thousands of dollars) 1994 1993 1992 -------- ---------------- Service cost-benefits earned during the period$13,715$11,160$10,984 Plus (less): Interest cost on projected benefit obligation49,06749,34646,171 Return on plan assets at expected long-term rate (47,281)(45,032) (43,877) Amortization 5,781 1,364 1,239 ------- ------- ------- Net pension cost $21,282 $16,838 $14,517 Assumptions used to determine pension cost were: Discount rate 7.25% 8.25% 8.50% Average rate of increase in future compensation levels 4.35% 5.35% 6.70% Expected long-term rate of return on assets8.75%8.75% 9.00% ------- ------- ------- Actual return on plan assets $ 4,384 $69,208 $38,489 Service cost for 1993 does not reflect costs incurred in connection with an early retirement program offered by the NEES subsidiaries in that year (see Note F-3).
The following table sets forth the plans' funded status at December 31 (millions of dollars): ------------------------------------------------------------ Retirement Plans ------------------------------------------------------------ 1994 1993 ---------------------------------------------------------- Union Non-Union Supple- Union Non-unionSupple- Employee Employee mental EmployeeEmployee mental Plans Plans Plans Plans Plans Plans -------- -------- ------- ---------------- ------- Benefits earned Actuarial present value of accumulated benefit liability: Vested $251 $308 $38 $251 $333 $40 Non-vested 8 9 - 20 6 - ---- ---- ---- ---- ---- ---- Total $259 $317 $38 $271 $339 $40 Reconciliation of funded status Actuarial present value of projected benefit liability$303 $355 $44 $310 $383 $44 Unrecognized prior service costs(8) (4) (5) (8) (6) (4) SFAS No. 87 transition liability not yet recognized (amortized)- (1) (5) - (1) (5) Net gain (loss) not yet recognized (amortized) (13) (33) 2 (11) (45) (2) Additional minimum liability recognized - - 5 - 8 7 ----- ----- ----- ----- ----- ----- 282 317 41 291 339 40 Pension fund assets at fair value293 323 - 302 318 - SFAS No. 87 transition asset not yet recognized (amortized)(13) - - (14) - - ----- ----- ----- ----- ----- ----- 280 323 - 288 318 - ----- ----- ----- ----- ----- ----- Accrued pension/(prepaid) payments recorded on books $ 2 $ (6) $41 $ 3 $ 21 $40
The assumed discount rate and the assumed average rate of increase in future compensation levels used to calculate pension cost changed effective January 1, 1995 to 8.25 percent and 4.63 percent, respectively. The expected long-term rate of return on assets used to calculate pension cost was not changed from the level shown in the table above. The plans' funded status at December 31, 1994 was calculated using these revised rates. Plan assets are composed primarily of corporate equity, guaranteed investment contracts, debt securities, and cash equivalents. 2.Postretirement benefit plans other than pensions In 1993, SFAS No. 106, "Employer's Accounting for Postretirement Benefits Other than Pensions" (PBOPs) went into effect. The NEES subsidiaries provide health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage. The total cost of PBOPs for 1994 and 1993 includes the following components: Year ended December 31 (thousands of dollars) 1994 1993 ---------- ---------- Service cost-benefits earned during the period$ 8,575 $ 8,160 Plus (less): Interest cost on the accumulated benefit obligation 27,813 30,457 Return on plan assets at expected long-term rate (7,821) (5,089) Amortization 18,273 18,418 ------- ------- Net postretirement benefit cost $46,840 $51,946 ------- ------- Actual return on plan assets $ 185 $ 5,249 The following table sets forth benefits earned and the plans' funded status: At December 31 (millions of dollars) 1994 1993 ---------- ---------- Accumulated postretirement benefit obligation: Retirees $226 $249 Fully eligible active plan participants 42 23 Other active plan participants 95 130 ----- ----- Total benefits earned 363 402 Unrecognized transition obligation (331) (350) Net gain (loss) not yet recognized 43 (7) ----- ----- 75 45 Plan assets at fair value 109 86 Prepaid postretirement benefit costs recorded on books $ 34 $ 41 1995 1994 1993 ------ ------ ------ Assumptions to determine postretirement benefit cost: Discount rate 8.25% 7.25% 8.25% Expected long-term rate of return on assets 8.50% 8.50% 8.50% Health care cost rate - 1994 and 1993 - 11.00% 12.00% Health care cost rate - 1995 to 2004 8.50% 8.50% 9.50% Health care cost rate - 2005 and beyond 6.25% 6.25% 7.25% The plans' funded status at December 31, 1994 and 1993 presented above was calculated using the assumed rates in effect for 1995 and 1994, respectively. The health care cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed rates by 1 percent in each year would increase the accumulated postretirement benefit obligation as of December 31, 1994 by approximately $54 million and the net periodic cost for the year 1994 by approximately $7 million. The NEES subsidiaries fund the annual tax deductible contributions. Plan assets are invested in equity and debt securities and cash equivalents. Prior to 1993, NEES subsidiaries recorded the cost of PBOPs when paid. These costs amounted to approximately $13 million in 1992. Each of the NEES subsidiaries has been permitted to recover amounts on either a current and/or deferred basis, which are expected to at least equal the amounts calculated in accordance with this new accounting standard. Adoption of this new accounting standard did not have a significant impact on net income. 3.1993 Early retirement and special severance programs In February 1993, NEES subsidiary companies offered a voluntary early retirement program to non-union employees who were at least 55 years old with 10 years of service. This program was part of an organizational review with the goal of streamlining operations and reducing the work force. The early retirement offer was accepted by 344 employees. A special severance program was also announced in February 1993 for employees affected by the organizational review, but who were not eligible for, or did not accept, the early retirement offer. NEES subsidiaries recorded in the first quarter a one-time charge to 1993 earnings of approximately $18 million, after tax ($28 million, before tax), to reflect the cost of the early retirement and special severance programs which consisted principally of pension benefits. Note G - Short-term borrowings At December 31, 1994, NEES and its consolidated subsidiaries had lines of credit and standby bond purchase facilities with banks totaling $663 million. These lines and facilities were used at December 31, 1994 for $2 million of direct borrowings, and for liquidity support for $232 million of commercial paper borrowings and $342 million of NEP mortgage bonds in tax-exempt commercial paper mode (see Note H). Fees are paid on the lines and facilities in lieu of compensating balances. The weighted average rate on outstanding short-term borrowings was 6.1 percent at December 31, 1994. The fair value of the NEES subsidiaries' short-term debt equals carrying value. Note H - Long-term debt Substantially all the properties of NEP, Massachusetts Electric, and Narragansett are subject to the lien of mortgage indentures under which mortgage bonds have been issued. The aggregate payments to retire maturing long-term debt are as follows: (thousands of dollars) 1995 1996 1997 1998 1999 ------- --------------- -------- ------- Maturing long-term debt $35,000$10,000 $ 65,500$ 60,000 $33,000 Mandatory prepayments: Hydro-Transmission Companies11,52011,520 11,520 11,520 11,520 Granite State Electric Company3,4001,000 NEEI 16,000 75,000 75,000 50,000 -------------- ---------------- ------- Total $65,920$97,520 $152,020$121,520 $44,520 The terms of $342 million of variable rate pollution control revenue bonds collateralized by NEP mortgage bonds require NEP to reacquire the bonds under certain limited circumstances. At December 31, 1994, interest rates on NEP's variable rate bonds ranged from 3.30 percent to 5.60 percent. Also, at December 31, 1994, interest rates on NEEI's debt ranged from 5.94 percent to 7.00 percent. NEP and the retail subsidiaries have issued $56 million of long-term debt to date in 1995 at interest rates ranging from 7.79 percent to 8.45 percent. At December 31, 1994, the NEES subsidiaries' long-term debt had a carrying value of approximately $1,586,000,000 and had a fair value of approximately $1,555,000,000. To estimate fair value, the carrying amount was used for debt that reprices frequently at market rates because the carrying amount is a reasonable estimate of fair value. For all other debt, the fair market value of the NEES subsidiaries' long-term debt was estimated based on the quoted prices for similar issues or on the current rates offered to the NEES companies for debt of the same remaining maturity. Report of Management The management of New England Electric System is responsible for the integrity of the consolidated financial statements included in this annual report. The financial statements were prepared in accordance with generally accepted accounting principles using management's informed best estimates and judgments where appropriate to fairly present the financial condition of the NEES companies and their results of operations. The information included elsewhere in this report is consistent with the financial statements. The NEES companies maintain an accounting system and system of internal controls which are designed to provide reasonable assurance as to the reliability of the financial records, the protection of assets, and the prevention of any material misstatement of the financial statements. The NEES companies' accounting controls have been designed to provide reasonable assurance that errors or irregularities, which could be material to the financial statements, are prevented or detected by employees within a timely period as they perform their assigned functions. The NEES companies' internal auditing staff independently assesses the effectiveness of internal controls and recommends improvements when appropriate. Coopers & Lybrand L.L.P., the NEES companies' independent accountants, are engaged to audit and express their opinion on the financial statements. Their audit includes a review of internal controls to the extent required by generally accepted auditing standards. The Audit Committee, composed solely of outside directors, meets periodically with management, the internal auditor, and the independent accountants to ensure that each is carrying out its responsibilities and to discuss auditing, internal accounting control, and financial reporting matters. Both the internal auditor and the independent accountants have free access to the Audit Committee, without management present, to discuss the results of their audit work. /s/ John W. Rowe /s/ Alfred D. Houston John W. Rowe Alfred D. Houston President and Executive Vice President Chief Executive Officer and Chief Financial Officer Report of Independent Accountants To the Board of Directors and Shareholders of New England Electric System: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of New England Electric System and subsidiaries (the Company) as of December 31, 1994 and 1993 and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 1994 and 1993, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. Boston, Massachusetts /s/ COOPERS & LYBRAND L.L.P. February 27, 1995
Shareholder Information New England Electric System common shares 1994 1993 --------------------------------------------------- Price range Price range ----------------Dividend---------------Dividend High Low declared High Low declared -------------- --------------- --------------- First quarter $39 $35-1/8 $.56 $42-1/4 $36-7/8 $.54 Second quarter $37-5/8$31-1/2 $.57-1/2$42-7/8 $39-3/8 $.56 Third quarter $34 $28-7/8 $.57-1/2$43-3/8 $40-3/4 $.56 Fourth quarter $32 7/8$29 1/2 $.57 1/2$42 $37 $.56
The total number of shareholders at December 31, 1994 was 54,593. Selected quarterly financial information (unaudited)
(thousands of dollars) 1st quarter 2nd quarter 3rd quarter4th quarter* ----------- ---------- ---------------------- 1994 Operating revenue $576,906 $517,078 $591,633 $557,412 Operating income $ 91,862 $ 57,716 $ 84,354 $ 62,564 Net income $ 69,273 $ 33,584 $ 58,851 $ 37,718 Net income per average share$ 1.07$ .51 $ .91 $ .58 1993 Operating revenue $579,490 $518,136 $576,644 $559,708 Operating income $ 80,711 $ 46,046 $ 82,498 $ 93,688 Net income $ 53,586 $19,146 $ 55,531 $ 61,960 Net income per average share$ .82$ .30 $ .85 $ .96 *See Notes A-2 and E-3 for discussion of items that increased 1993 fourth quarter earnings.
Shareholder services Shareholders may direct questions or acquire additional information about shareholder records, quarterly dividend payments, or address changes by contacting a shareholder services representative. The following services are available to shareholders who have shares registered in their own name: direct deposit of dividends, automatic investments, dividend reinvestment, and safekeeping of certificated shares. New England Electric System Shareholder Services Department Post Office Box 770 Westborough, Massachusetts 01581-0770 Toll-Free Number: 1-800-466-7215 Local Number: 508-389-2699 Dividends on common shares Dividends are generally payable on the first business day of January, April, July, and October. Transfer agent Questions about the transfer of certificate shares should be directed to: Bank of Boston, Transfer Processing Post Office Box 644, Mail Stop 45-01-05 Boston, Massachusetts 02102-0644 617-575-3120 Stock exchange listings New York Stock Exchange Boston Stock Exchange Trading symbol NES Annual meeting notice The annual meeting of New England Electric System will be held at Lowell Memorial Auditorium, Lowell, Massachusetts, on April 25, 1995, at 10:30 a.m. Form 10K and Statistical Report Copies of the annual report on Form 10K to the Securities and Exchange Commission and a Statistical Report for 1994 can be obtained, free of charge, by writing to: New England Electric System Investor Relations 25 Research Drive Westborough, Massachusetts 01582 The name "New England Electric System" means the trustee or trustees for the time being (as trustee or trustees but not personally) under an Agreement and Declaration of Trust dated January 2, 1926, as amended, which is hereby referred to, and a copy of which, as amended, has been filed with the Secretary of The Commonwealth of Massachusetts. Any agreement, obligation, or liability made, entered into, or incurred by or on behalf of New England Electric System binds only its trust estate, and no shareholder, director, trustee, officer, or agent thereof assumes or shall be held to any liability therefor. This report is not to be considered as an offer to sell or buy or solicitation of an offer to sell or buy any security. System Directors As of December 31, 1994 Joan T. Bok Chairman of the Board New England Electric System Westborough, Massachusetts Corporate Responsibility Committee Executive Committee Paul L. Joskow Professor of Economics and Management Massachusetts Institute of Technology Cambridge, Massachusetts Audit Committee John M. Kucharski Chairman, President, and Chief Executive Officer EG&G, Inc. Wellesley, Massachusetts Compensation Committee Edward H. Ladd Chairman Standish, Ayer & Wood, Inc., Investment counselors Boston, Massachusetts Executive Committee Joshua A. McClure Former President American Custom Kitchens, Inc. Providence, Rhode Island Corporate Responsibility Committee Malcolm McLane Of Counsel Orr & Reno, P.A., Attorneys Concord, New Hampshire Audit Committee Felix A. Mirando, Jr. Private investor Osterville, Massachusetts Compensation Committee John W. Rowe President and Chief Executive Officer New England Electric System Westborough, Massachusetts Corporate Responsibility Committee Executive Committee George M. Sage President and Treasurer Bonanza Bus Lines, Inc. Providence, Rhode Island Compensation Committee Executive Committee Charles E. Soule President and Chief Executive Officer Paul Revere Insurance Group Worcester, Massachusetts Audit Committee Anne Wexler Chairman The Wexler Group, Management consultants Washington, D. C. Corporate Responsibility Committee Executive Committee James Q. Wilson Professor of Management University of California at Los Angeles Corporate Responsibility Committee James R. Winoker Chief Executive Officer Belvoir Properties, Inc., Providence, Rhode Island Audit Committee Compensation Committee System Officers As of December 31, 1994 John W. Rowe President and Chief Executive Officer Alfred D. Houston Executive Vice President and Chief Financial Officer Frederic E. Greenman Senior Vice President, General Counsel, and Secretary John W. Newsham Vice President Richard P. Sergel Vice President Jeffrey D. Tranen Vice President Michael E. Jesanis Treasurer System Subsidiaries Massachusetts Electric Company 25 Research Drive, Westborough, Massachusetts 01582 John H. Dickson, President The Narragansett Electric Company 280 Melrose Street, Providence, Rhode Island 02901 Robert L. McCabe, President Granite State Electric Company 407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766 Lydia M. Pastuszek, President New England Power Company 25 Research Drive, Westborough, Massachusetts 01582 Narragansett Energy Resources Company 280 Melrose Street, Providence, Rhode Island 02901 New England Electric Resources, Inc. 25 Research Drive, Westborough, Massachusetts 01582 John L. Levett, President New England Electric Transmission Corporation 407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766 New England Energy Incorporated 25 Research Drive, Westborough, Massachusetts 01582 New England Hydro-Transmission Corporation 407 Miracle Mile, Suite 1, Lebanon, New Hampshire 03766 New England Hydro-Transmission Electric Company, Inc. 25 Research Drive, Westborough, Massachusetts 01582 New England Power Service Company 25 Research Drive, Westborough, Massachusetts 01582 [LOGO OF RECYCLED PAPER APPEARS HERE] New England Electric System 25 Research Drive Westborough, Massachusetts 01582 Telephone 508-366-9011 Appendix of Graphic and Image Material Appearing in New England Electric System 1994 Annual Report 1. The cover contains images of a canoe, a pen, a mortarboard, and a lighthouse. 2. Foldout inside cover contains a map of New England and indicates service areas and generating facilities. 3. The financial highlights page contains a graph comparing 1994 Return on Equity percentages for New England Electric System 12.7%, the median of U.S. Electric Utilities 11.4%, and the median of New England/New York Electric Utilities 11.04%. 4. Pictures of Joan T. Bok, Chairman of the Board, and John W. Rowe, President and Chief Executive Officer, appear on the pages of the letter to shareholders. 5. A picture of a mortarboard and a picture of Douglas Smith, senior technical representative, appear in the Customer Focus section. 6. A picture of a lighthouse and a picture of Paul Stasiuk, senior analyst, appear in the Competitive Marketplace section. 7. A picture of a canoe and a picture of Paula Hamel, senior environmental engineer, appear in the Environment section. 8. A picture of a fountain pen and a picture of Masheed Hegi, consulting engineer, appear in the New Rules section. 9. The following graphs appear in the Financial Review Section: a. Earnings per average share: $2.77 in 1991, $2.85 in 1992, $2.93 in 1993, and $3.07 in 1994. b. The annual rate of dividends declared per share: $2.08 in 1991, $2.16 in 1992, $2.24 in 1993, and $2.30 in 1994. c. Percentage growth in kilowatt hour sales to ultimate customers: negative 1.2% in 1991, 0.4% in 1992, 1.4% in 1993, and 1.6% in 1994. d. Customers served per employee: 227 in 1991, 236 in 1992, 259 in 1993, and 261 in 1994. e. 1994 New England Electric System energy mix: 31% coal, 10% oil, 19% nuclear, 12% hydro, 6% renewables, and 16% gas. f. 1994 Distribution of Revenue: 24% Fuel, 9% Purchased Power (excluding fuel), 11% Wages and Benefits, 18% other O&M, 13% Depreciation and Amortization, 11% Taxes, 5% Interest and Preferred Dividends, 9% Earnings - Common Shares. g. 1994 Revenue by Sales Classification: 43% residential, 32% small and medium commercial and industrial, 20% large commercial and industrial with SED contracts, and 5% large commercial and industrial without SED contracts. h. Diverse Regulation - percent of 1994 electric revenue: 73% Federal Energy Regulatory Commission, 19% Massachusetts, 7% Rhode Island, and 1% New Hampshire. EX-24 7 EXHIBIT 24 POWER OF ATTORNEY Each of the undersigned directors of New England Electric System (the "Company"), individually as a director of the Company, hereby constitutes and appoints John G. Cochrane, Thomas F. Killeen, and Geraldine M. Zipser, individually, as attorney- in-fact to execute on behalf of the undersigned the Company's annual report on Form 10-K for the year ended December 31, 1994, to be filed with the Securities and Exchange Commission, and to execute any appropriate amendment or amendments thereto as may be required by law. Dated this 28th day of February, 1995. s/ Joan T. Bok s/ John W. Rowe __________________________ _________________________ Joan T. Bok John W. Rowe s/ Paul L. Joskow s/ George M. Sage __________________________ _________________________ Paul L. Joskow George M. Sage s/ Charles E. Soule __________________________ _________________________ John M. Kucharski Charles E. Soule s/ Edward H. Ladd s/ Anne Wexler __________________________ _________________________ Edward H. Ladd Anne Wexler s/Joshua A. McClure __________________________ _________________________ Joshua A. McClure James Q. Wilson s/ Malcolm McLane s/ James R. Winoker __________________________ _________________________ Malcolm McLane James R. Winoker _________________________ Felix A. Mirando, Jr. EX-27 8 EXHIBIT 27 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT 1,000 DEC-31-1994 DEC-31-1993 DEC-31-1994 DEC-31-1993 12-MOS 12-MOS PER-BOOK PER-BOOK 3,716,721 3,482,501 423,713 455,127 525,723 464,614 418,684 393,636 0 0 5,084,841 4,795,878 64,970 64,970 736,823 736,823 779,045 728,075 1,580,838 1,529,868 0 0 147,016 147,528 1,520,488 1,511,589 233,970 71,775 0 0 0 0 65,920 12,920 0 0 0 0 0 0 1,536,609 1,522,198 5,084,841 4,795,878 2,243,029 2,233,978 128,257 121,124 1,818,276 1,809,911 1,946,533 1,931,035 296,496 302,943 16,071 13,657 312,567 316,600 97,005 107,770 199,426 190,223 8,697 10,585 199,426 188,176 148,456 144,233 93,500 100,777 417,966 498,651 $3.07 $2.93 $3.07 $2.93 Total deferred charges includes other assets and accrued Yankee Atomic costs. Preferred stock reflects preferred stock of subsidiaries. Preferred stock dividends reflect preferred stock dividends of subsidiaries. Short-term notes includes commercial paper obligations. EX-10 9 EXHIBIT 10(E) Exhibit 10(e) MEMORANDUM OF UNDERSTANDING WHEREAS, New England Power Company (NEP) provides all requirements electric service at wholesale to its retail affiliates, Massachusetts Electric Company, The Narragansett Electric Company, and Granite State Electric Company (the NEES Retail Companies) operating in the respective states of Massachusetts, Rhode Island, and New Hampshire; WHEREAS, the Massachusetts Department of Public Utilities, the Rhode Island Public Utilities Commission, and the New Hampshire Public Utilities Commission regulate the retail rates of the NEES Retail Companies, which retail rates include wholesale purchased power costs paid to NEP under wholesale rates regulated by the Federal Energy Regulatory Commission; WHEREAS, NEP's cost of providing service and wholesale rates are affected by the new resources that NEP adds to meet the electricity requirements of retail customers in Massachusetts, Rhode Island, and New Hampshire; WHEREAS, the State Commissions have in place independent processes through which they review the resource plans and decisions by NEP prior to the time that those decisions are reflected in wholesale rates to the NEES Retail Companies; and WHEREAS, the State Commissions, the NEES Retail Companies, and NEP believe that plans and resource decisions can be implemented most effectively under a coordinated, consensual, and consistent process of review; NOW THEREFORE, NEP and the NEES Retail Companies commit to do the following: I. Definitions. As used in this Memorandum: (A) "Regional Integrated Resource Plan" means a fifteen-year, system wide resource plan filed by NEP and each NEES Retail Company with each respective State Commission that includes: (1) a forecast of demands and kilowatthour usage by retail customers; (2) an inventory of existing resources; (3) an identification of additional resource needs; (4) a projection of the amount of capacity to be added through Significant New Supply Side Commitments and other supply side resources that are not Significant New Supply Side Commitments; (5) a projection of demand side resources expected to be developed over the planning horizon; (6) plans for compliance with new environmental laws, regulations, orders, or consent decrees before courts or regulatory agencies at existing units involving significant expenditures, including NEP's proposals to achieve compliance with the regulatory requirements under the Clean Air Act Amendments of 1990 at its eight units at the Salem Harbor and Brayton Point Stations and an evaluation of those proposals against other alternatives in the market; (7) a two-year implementation plan designed to detail how the Regional Integrated Resource Plan will be developed and implemented in the first two years; and (8) any other information required to be filed with the State Commission under state law or State Commission regulation. (B) "Significant New Supply Side Commitment" means a commitment to either (1) a new contract with a power supplier ("Purchased Power Contract") or (2) a new generating project proposed by NEP that is incorporated in a unit power contract with the NEES Retail Companies pursuant to Paragraph III ("NEP Unit Power Contract"), which commitment: (a) is executed or whose construction will commence after the Regional Integrated Resource Plan is filed; (b) extends for a period of three years or longer; (c) involves the purchase of an entitlement in at least 30 megawatts of additional capacity or requires the construction of a new generating unit having a total capacity greater than 30 megawatts; and (d) is intended to serve the electricity requirements of the NEES retail companies. (C) "FERC" means the Federal Energy Regulatory Commission. (D) "State Commission" means the Massachusetts Department of Public Utilities, New Hampshire Public Utilities Commission, and Rhode Island Public Utilities Commission together with any other agency or agencies that are authorized under state law to receive or review utility forecasts and plans in Massachusetts, New Hampshire, and Rhode Island. (E) "All Requirements Tariff" means FERC Electric Tariff, Original Volume Number 1 of New England Power Company under which NEP makes all-requirements sales to the NEES Retail Companies and other wholesale customers. II. Coordinated State Review of the Regional Integrated Resource Plans for the NEES Companies. (A) NEP and each NEES Retail Company shall jointly and concurrently file at least once every two years a Regional Integrated Resource Plan with each NEES Retail Company's respective State Commission. (B) Each State Commission will review the Regional Integrated Resource Plan in accordance with state law. (C) Within 30 days following either (1) the completion of reviews or the receipt of rulings by all State Commissions on the Regional Integrated Resource Plan filing or (2) one year following the filing of the Regional Integrated Resource Plan, whichever occurs first, NEP and the NEES Retail Companies shall file a compliance plan which shall: (a) notify all State Commissions that the rulings on the Regional Integrated Resource Plans are consistent; or (b) notify all State Commissions that the rulings on the Regional Integrated Resource Plan are inconsistent, identify all such inconsistencies, propose a resolution designed to reconcile the inconsistencies, and request a joint hearing before the State Commissions on the compliance filing. (D) The State Commissions shall have the opportunity to supplement or revise their rulings in response to the compliance plan under Paragraph II.(C) by acting within 90 days of the request. III. State Commission Review of Significant New Supply Side Commitments. (A) On or before its next general wholesale rate filing, NEP shall file with FERC amendments to its All Requirements Tariff requiring: (1) all Significant New Supply Side Commitments, wherever located, to be made initially by the NEES Retail Companies, subject to review by their respective State Commissions under Paragraph III.(B), and conditioned upon a successful completion of that review, and (2) all Significant New Supply Side Commitments remaining after state review to be assigned by the NEES Retail Companies to NEP under Paragraph III.(C). (B) The NEES Retail Companies shall execute all Purchased Power Contracts that represent Significant New Supply Side Commitments and all such contracts shall include a provision requiring an assignment to NEP in accordance with the terms of Paragraph III.(C). In addition, the NEES Retail Companies shall sign NEP Unit Power Contracts for all projects constructed and owned by NEP that represent Significant New Supply Side Commitments under which NEP's rate recovery of appropriate project costs will be through its All Requirements Tariff. The NEES Retail Companies shall file each of these Significant New Supply Side Commitments with their respective State Commissions before the Significant New Supply Side Commitment becomes effective. Each State Commission shall have 90 days to review the Significant New Supply Side Commitment; provided, however, that any State Commission may extend the review period for itself and all other State Commissions for up to an additional 30 days by issuing a notice or order extending the review period. If during the review period, as it may be extended, any State Commission, acting pursuant to state law and subject to appellate review, objects to the Significant New Supply Side Commitment or any of its terms, then the Significant New Supply Side Commitment shall be rendered null and void, and NEP and all NEES Retail Companies shall be precluded from going forward with the Significant New Supply Side Commitment. (C) If no State Commission objects to a Significant New Supply Side Commitment within the review period, the Significant New Supply Side Commitment shall become effective in accordance with its terms. If the Significant New Supply Side Commitment is a Purchased Power Contract, the NEES Retail Companies shall assign it to NEP, and if the Significant New Supply Side Commitment is a NEP Unit Power Contract, NEP may proceed with the project's development. (D) If after the date this Memorandum is executed: (1) A NEES Retail Company terminates all or any part of its purchases under the All-Requirements Tariff; or (2) A new law, rule, or order promulgated by a legislature, court, regulatory agency or other lawful authority limits the right of any NEES Retail Company to be the exclusive seller of electricity at retail within its current franchise territory; or (3) A new law, rule, or order promulgated by a legislature, court, regulatory body or other lawful authority limits NEP's right to make sales to any NEES Retail Company under the All-Requirements Tariff at prices established using NEP's reasonable and prudent cost of providing service as determined by FERC, then the costs that NEP has incurred to serve that NEES Retail Company shall be allocated to and paid by that NEES Retail Company and not allocated to or paid by any other NEES Retail Company. (E) The procedures established in this Section do not represent in any way a preapproval process for the rate recovery by NEP of the costs associated with the Significant New Supply Side Commitment, and no action or failure to object by a State Commission shall bind the State Commission in any way in any future wholesale rate proceeding before the FERC in which NEP seeks rate recovery of the costs associated with the Significant New Supply Side Commitment. Specifically, failure to object to a Significant New Supply Side Commitment shall not preclude the State Commission from arguing to FERC in a later wholesale rate proceeding that NEP's entry into the Significant New Supply Side Commitment was unreasonable or imprudent. (F) The procedures set forth in this Section shall apply only to the development of Significant New Supply Side Commitments. Nothing in this Memorandum shall restrict or limit the rights or management discretion of NEP or the NEES Retail Companies to operate and manage their existing resources and the Significant New Supply Side Commitments that become effective or are developed following the State Commission reviews under this Memorandum, provided, however, that nothing in this Memorandum shall affect the existing authority of FERC, or the State Commissions with rate jurisdiction over reassigned resources, to determine following an investigation in which interested persons are permitted to intervene whether the costs incurred are appropriately recovered in jurisdictional rates. Significant New Supply Side Commitments shall not include investments or improvements associated with: (1) the ongoing operation or management of existing units and the Significant New Supply Side Commitments that have been developed under this Memorandum; or (2) compliance with environmental laws, regulations, orders, or consent decrees before courts or regulatory agencies. The Manchester Street Repowering Project, the replacement of units at the Vernon Hydro Station, and purchased power contracts made prior to the effective date of this Agreement are committed resources and shall not be included in the definition of a Significant New Supply Side Commitment and shall not be subject to the procedures set forth in this Memorandum, provided, however, that all contracts executed as a result of NEP's request for proposals dated December 17, 1991 (the Green RFP) shall be treated as Significant New Supply Side Commitments and shall be subject to the procedures set forth in this Memorandum. IV. Conservation and Load Management Programs. (A) In an Offer of Partial Settlement filed with and approved by FERC in Docket Nos. ER 88-630-000 et al. (the W-10 Partial Settlement), NEP agreed to cease wholesale rate recovery of Nondispatchable Program Costs associated with conservation and load management (C&LM) programs "whenever a state commission includes Nondispatchable Program Costs of that affiliate in retail rates." (W-10 Partial Settlement, II.E.3.). NEP also reserved its right to seek recovery "in wholesale rates for any expenditures related to C&LM . . . incurred on or after January 1, 1993." (Id at II.E.5.). Following the approval of the W-10 Partial Settlement, each of the State Commissions has included the Nondispatchable Program Costs of its respective NEES Retail Company in retail rates and NEP hereby waives its right under Section II.E.5 of the W-10 Partial Settlement to seek recovery of Nondispatchable Program Costs in wholesale rates during the effective period of this Memorandum of Understanding. Nothing in this Memorandum shall affect or restrict NEP's ability to seek recovery of Planning and Dispatchable Program Costs in wholesale rates or prevent the reallocation of these costs back to the NEES Retail Companies, provided, however, that if NEP seeks to recover these costs, NEP will continue its practice of filing all relevant cost recovery information with the State Commissions at the same time that it files this information with FERC. For purposes of this Memorandum, "Planning and Dispatchable Program Costs" and "Nondispatchable Program Costs" shall have the same meanings as in the W-10 Partial Settlement (II.D.1. and 2.). (B) NEP agrees to make available to each State Commission information, data, and analysis necessary to establish the cost effectiveness of each NEES Retail Company's C&LM program when that program is evaluated from the perspective of the integrated NEES System based on NEP's marginal costs of providing electricity supplies in the context of the integrated, least cost resource plan, as well as from the perspective of the NEES Retail Companies based on NEP's wholesale rate. V. Term of Memorandum. The Term of this Memorandum shall commence when each State Commission has approved this Agreement and FERC has approved NEP's filing under Paragraph III.(A), and shall continue for the life of any Significant New Supply Side Commitment that has become effective under this Memorandum, provided, however, that NEP or any NEES Retail Company may terminate their obligations to continue the contracting and filing procedure for future Significant Supply Side Commitments under Paragraph III, and NEP may rescind the modifications to its All-Requirements Tariff made pursuant to Paragraph III(A) by giving two years written notice to each State Commission. Notwithstanding the foregoing, NEP or any NEES Retail Company may immediately terminate such obligations and rescind such modifications if the following conditions are no longer met: (A) All Significant New Supply Side Commitments, all contracts with qualifying facilities wherever they are located, and all other purchases from any supply side resource having a capacity greater than one megawatt are assigned to NEP by the NEES Retail Companies except for any qualifying facilities signed by Massachusetts Electric Company pursuant to the October 21, 1991 Offer of Settlement approved in Docket Nos. E.F.S.C. 91-24 and D.P.U. 91-114; (B) An exemption for NEP and Massachusetts Electric Company from the Massachusetts Integrated Resource Management regulations set forth in 220 C.M.R. 10.00 et seq. is granted and remains in effect, and the review of Significant New Supply Side Commitments under this Memorandum is the exclusive procedure for the prior review of Significant New Supply Side Commitments by State Commissions other than any further reviews that may be required by environmental and siting laws within the state in which the project is to be located or; (C) Nondispatchable Program Costs are recovered in retail rates, and the State Commissions recognize as reasonable and appropriate all conservation and load management commitments made by or to other State Commissions when reviewing the Regional Integrated Resource Plans that are filed under Section I.B. Granite State Electric Company Massachusetts Electric Company s/Lydia M. Pastuszek s/John H. Dickson By: Lydia M. Pastuszek By: John H. Dickson Title: President Title: President New England Power Company The Narragansett Electric Company s/Jeffrey D. Tranen s/Robert L. McCabe By: Jeffrey D. Tranen By: Robert L. McCabe Title: President Title: President DATE: July 21, 1993 EX-10 10 EXHIBIT 10(L) Exhibit 10(l) 1995 FORM NEW ENGLAND POWER SERVICE COMPANY 25 Research Drive Westborough, Massachusetts 01582 SERVICE CONTRACT December 30, 1994 Company Address New England Power Service Company (hereinafter called Service Company) is a company engaged primarily in the rendering of services to companies in the New England Electric System holding-company system. The organization, conduct of business and method of cost allocation of the Service Company are designed to meet the requirements of Section 13 under the Public Utility Holding Company Act of 1935 and the rules and regulations promulgated thereunder to the end that services performed by the Service Company for said associate companies will be rendered to them at cost, fairly and equitably allocated. Services will be rendered by Service Company only upon receipt from time to time of specific or general request therefor. Said requests may always be modified or cancelled by you at your discretion. The parties hereto agree as follows: 1. The Service Company agrees to furnish you upon the terms and conditions herein set forth such of the services described in Schedule 1 hereto as you may from time to time request. Service Company will also furnish, if available, such services not described in Schedule 1 as you may request. Notwithstanding the foregoing the Service Company shall not furnish under this agreement any engineering, construction, or maintenance services for a nuclear generating plant. 2. The Service Company has and will maintain a staff trained and experienced in the engineering, construction, operation, maintenance and management of public utility properties. In addition to the services of its own staff, Service Company will, after consultation with you concerning services to be rendered pursuant to your request, arrange for services of non-affiliated experts, consultants, accountants and attorneys. 3. All of the services rendered under this agreement will be at actual cost thereof. Direct charges will be made for services where a direct allocation of cost is possible. The methods of determining such costs and the allocation thereof are set forth in Schedule II hereto. These methods are reviewed annually and more frequently, if appropriate. Such methods may be modified or changed by Service Company without the necessity of an amendment of this agreement provided that in each instance all services rendered hereunder will be at actual cost thereof, fairly and equitably allocated, and all in accordance with the requirements of the Public Utility Holding Company Act of 1935 and the rules and regulations and orders thereunder. You will be advised from time to time of any material changes in such methods. 4. Bills will be rendered during the first week of each month covering amounts due for the month calculated on an estimated basis using the actual expenses incurred during the previous month. This estimated amount would be adjusted on the bill to be rendered during the first week of the following month. Any amount remaining unpaid after fifteen days following receipt of the bill shall bear interest thereon from the date of the bill at an annual rate of 2% above the lowest interest rate then being charged by the First National Bank of Boston on 90 day commercial loans. Services will be performed hereunder for not more than one year commencing January 1, 1995, and continuing through December 31, 1995, unless terminated at an earlier date by either party giving thirty days' written notice to the other of such termination at the end of any month. 5. This agreement will be subject to termination or modification at any time to the extent its performance may conflict with any federal or state law or any rule, regulation or order of a federal or state regulatory body having jurisdiction. The agreement shall be subject to approval of any federal or state regulatory body whose approval is a legal prerequisite to its execution and delivery or performance. NEW ENGLAND POWER SERVICE COMPANY By: Treasurer Accepted , 19 By EX-10 11 EXHIBIT 10(Y) Exhibit 10(y) AMENDING AGREEMENT ------------------ THIS AMENDING AGREEMENT dated as of the 29th day of October, 1993 BETWEEN: TRANSCANADA PIPELINES LIMITED a Canadian corporation ("TransCanada") AND NEW ENGLAND POWER COMPANY a Company incorporated under the laws of the State of Massachusetts ("Shipper") WITNESSETH THAT: WHEREAS TransCanada and Shipper are parties to a Firm Service Contract dated January 6, 1992 as amended (the "Firm Service Contract"), which provides for the firm delivery of gas by TransCanada to a point on the international border near Iroquois, Ontario (the "Delivery Point"); and WHEREAS Shipper requested and TransCanada agreed, on the terms and conditions set forth herein, to amend the volume of gas to be transported under the Firm Service Contract for the period between November 1, 1993 and October 31, 1994. NOW THEREFORE, in consideration of the mutual covenants and agreements hereinafter set forth, and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, TransCanada and Shipper hereby agree as follows: 1. Article II of the Firm Service Contract is deleted in its entirety and the following is substituted therefor: "ARTICLE II - GAS TO BE TRANSPORTED - ----------------------------------- 2.1 Subject to the provisions of this Contract, the FS Toll Schedule, the List of Tolls, and the General Terms and Conditions referred to in Section 7.1 hereof, TransCanada shall provide transportation service hereunder for Shipper in respect of a volume of gas which, in any one day, from November 1, 1993 until October 31, 1994, shall not exceed 1406.6 10 3m3 and from November 1, 1994 until October 31, 2006, shall not exceed 1699.7 10 3m3 (the "Contract Demand")." 2. Subject to the amendments contained herein, the Firm Service Contract is hereby ratified and confirmed. TRANSCANADA PIPELINES UNITED s/ H. Feldman per s/ S. S. G. per NEW ENGLAND POWER COMPANY s/ Jeffrey W. VanSant per s/ John F. Malley per EX-10 12 EXHIBIT 10(Z) Exhibit 10(z) TEMPORARY TRANSPORTATION CONTRACT ASSIGNMENT THIS TEMPORARY ASSIGNMENT made effective as of the 27th day of October, 1993 BETWEEN: RENAISSANCE ENERGY LTD. ("Assignor") OF THE FIRST PART AND NEW ENGLAND POWER COMPANY ("Assignee") OF THE SECOND PART WITNESSES THAT: WHEREAS, TransCanada PipeLines Limited ("TransCanada") and Assignor are parties to a Firm Service Contract for firm transportation service to the Niagara, Ontario Delivery Point made as of November 1, 1993 (a copy of such contract made thereto to the date hereof being attached hereto as Exhibit " I " and forming a part hereof (said contract, being hereinafter called the "Contract"); and WHEREAS, Assignee has requested that Assignor assign part of Assignor's rights and obligations as Shipper under the Contract and Assignor has agreed to do so subject to the terms and conditions of this Assignment. NOW. THEREFORE. THIS AGREEMENT WITNESSES THAT in consideration of the covenants and agreements herein set forth, the parties hereto covenant and agree as follows: 1. Subject to paragraph 6 herein, during the operative term of this Assignment, Assignor does hereby grant, transfer, assign and set over unto Assignee, and Assignee accepts from Assignor, that portion of Assignor's service entitlement as shipper under the Contract equal to 333.6 10 3m3 per day (the "Assigned Volume"), together with the corresponding rights and obligations of Assignor as shipper under the Contract. 2. Subject to Paragraphs 6 and 8 herein, during the operative term of this Assignment, Assignee hereby covenants and agrees that it shall perform and observe the covenants and obligations of Assignor as shipper contained in the Contract insofar as they pertain to the Assigned Volume, to the same extent as Assignee would be obligated so to do were Assignee a party to the Contract, as shipper, with a service entitlement thereunder equal to the Assigned Volume. 3. This Assignment shall be in full force and effect as of and from 08:00 hours on November 1, (the "Date of First Delivery") (provided that, for the purposes of Assignee nominating service for the Date of First Delivery, this Assignment shall become effective as at 08:00 hours on the date immediately preceding the Date of First Delivery) and, subject to paragraph 4 hereof shall be operative for a term ending at 08:00 hours on November 1, 1994. Notwithstanding the foregoing, the operative term of this Assignment shall not extend beyond the term of the Contract. 4. In the event that Assignee fails to comply with paragraph 2 hereof, Assignor shall have the right to terminate this Assignment by following the termination procedure set forth in Section XVII of the General Terms and Conditions contained in TransCanada's Transportation Tariff as if Assignor were TransCanada, Assignee were Shipper and this Assignment was the Contract for this purpose. 5. Assignor will request TransCanada to acknowledge the assignment herein and to treat Assignee as shipper with a service entitlement under the Contract equal to the Assigned Volume during the operative term of this Assignment. Assignee hereby consents to such request and to such treatment, and for this purpose Assignee declares that all notices, nominations, requests, invoices, and other written communications may be given by TransCanada to Assignee as follows: (i) Mailing address: 25 Research Drive Westborough, Massachusetts 01582 (ii) Delivery address: Same as mailing address (iii) Nominations: Director of Fuel Supply Facsimile: (508) 898-3952 (iv) Legal and Other: Director of Fuel Supply 6. Assignee acknowledges that Assignor will not seek TransCanada's consent to this Assignment and that Assignor accordingly is and will remain obligated to TransCanada to perform and observe the covenants and obligations of shipper that are contained in the Contract in regard to the Assigned Volume insofar as TransCanada is concerned. Without limiting the generality of the foregoing, the Assignor and the Assignee acknowledge that the Assignor shall remain responsible for all gas imbalances (as such term is defined in Section XXII of the General Terms and Conditions in TransCanada's Transportation Tariff) and Energy-in-Transit balances associated with the Assigned volume and/or the Contract. Consequently, Assignee shall indemnify Assignor for and hold Assignor harmless from all charges that TransCanada may be entitled to collect from Assignor under the Contract in regard to the Assigned Volume in the event that Assignee fails to pay them. 7. Assignee shall be entitled to sub-assign all or part of the Assigned Volume, together with the corresponding rights and obligations under the Contract, to a third party by assigning all or part of its rights and obligations under this Assignment; provided that no such assignment shall relieve Assignee of its obligations to Assignor hereunder without Assignor's prior written consent, which consent shall not be unreasonably withheld. Notwithstanding any such sub-assignment or sub-assignments, Assignor is and will remain obligated to TransCanada to perform and observe the covenants and obligations of shipper that are contained in the Contract in regard to the Assigned Volume insofar as TransCanada is concerned. 8. Notwithstanding anything to the contrary herein set forth or implied, Assignor reserves and retains for itself exclusively any option or right to renew or otherwise extend the operative term of the Contract which may be contained in or granted by the Contract. 9. Assignee acknowledges that it has (or may obtain directly from TransCanada) a copy of the Transportation Tariff. 10. This Assignment and the rights and obligations of the parties hereunder are subject to all valid and applicable present and future laws, rules, regulations, and orders of any governmental or regulatory authority having jurisdiction or control over the parties hereto to either of them, or over the Contract. 11. This Assignment shall be construed in accordance with and governed by the laws of the Province of Alberta and the laws of Canada applicable therein. 12. This Assignment shall enure to the benefit of and be binding upon, the parties hereto and their respective successors and permitted assigns. IN WITNESS WHEREOF the parties hereto have duly executed and delivered this Assignment as of the day, month. and year first above written. RENAISSANCE ENERGY LTD. NEW ENGLAND POWER COMPANY - ---------------------- -------------------------- ASSIGNOR ASSIGNEE s/ Max Muselius s/ Jeffrey W. VanSant BY: BY: Vice President, Marketing Vice President TITLE: TITLE: s/ John F. Malley BY: BY: Vice President TITLE: TITLE: cc: TransCanada PipeLines Limited FAX: (403) 267-8620 S.K. Dorton FIRM SERVICE CONTRACT --------------------- THIS FIRM SERVICE CONTRACT FOR FIRM TRANSPORTATION SERVICE, made as of the 1st day of November, 1993. BETWEEN: TRANSCANADA PIPELINES LIMITED a Canadian corporation ("TransCanada") OF THE FIRST PART and RENAISSANCE ENERGY LTD- a company incorporated under the laws of the Province of Alberta ("Shipper") OF THE SECOND PART WITNESSES THAT: WHEREAS TransCanada owns and operates a natural gas pipeline system extending from a point near the Alberta/ Saskatchewan border where TransCanada's facilities interconnect with the facilities of NOVA Corporation of Alberta easterly to the Province of Quebec with branch lines extending to various points on the Canada/United States of America International Border; and WHEREAS Shipper, Norcen Energy Resources Limited, Rigel Oil and Gas Ltd., Wainoco Oil Corporation, Ulster Petroleum Ltd., Canadian Pioneer Energy Inc., Tarragon Oil and Gas Limited, Northbridge Gas Marketing, Inc. (collectively, the "Assignor"), and TransCanada are parties to a firm service contract to the Niagara Falls Delivery Point made as of the 28th day of July, 1989 having a Daily Contract Quantity of 904.0 10 3m3 (such firm service contract, as amended from time to time to the date hereof being hereinafter called the "Old Contract"); and WHEREAS pursuant to an amending agreement dated November 1, 1993, (the "Amending Agreement") Shipper was removed as a party to the Old Contract effective upon execution of this Contract by TransCanada and Shipper; and WHEREAS Shipper has satisfied in full, or TransCanada has waived, each of the conditions precedent set out in Sections 1.1 (b) and (c) of TransCanada's Firm Service Toll Schedule referred to in Section 7.1 hereof (the "FS Toll Schedule"); and WHEREAS Shipper has requested and TransCanada has agreed to transport volumes of gas, that are delivered by Shipper or Shipper's agent to TransCanada at the Receipt Point referred to in Section 3.2 hereof (the "Receipt Point"), to the Delivery Point referred to in Section 3.1 hereof (the "Delivery Point") pursuant to the terms and conditions of this Contract; and WHEREAS the volumes of gas delivered hereunder by Shipper or Shipper's agent to TransCanada are to be removed from the province of production of such gas by Shipper and/or Shipper's suppliers and/or its (their) designated agent(s) pursuant to valid and subsisting permits and/or such other authorizations in respect thereof. NOW THEREFORE THIS CONTRACT WITNESSES THAT, in consideration of the covenants and agreement herein contained, the parties hereto covenant and agree as follows: ARTICLE I - COMMENCEMENT OF SERVICE - ----------------------------------- 1.1 The date of commencement of service hereunder (the "Date of Commencement") shall be November 1, 1993. ARTICLE II - GAS TO BE TRANSPORTED - ---------------------------------- 2.1 Subject to the provisions of this Contract, the FS Toll Schedule, the List of Tolls, and the General Terms and Conditions referred to in Section 7.1 hereof, TransCanada shall provide transportation service hereunder for Shipper in respect of a volume of gas which, in any one day from the Date of Commencement until the 31st day of October, 2009, shall not exceed 419.0 10 3m3 (the "Contract Demand"). ARTICLE III - DELIVERY POINT AND RECEIPT POINT - ---------------------------------------------- 3.1 The Delivery Point hereunder is the point specified as such in Exhibit "1" which is attached hereto and made a part hereof. 3.2 The Receipt Point hereunder is the point specified as such in Exhibit "1" hereof. ARTICLE IV - TOLLS - ------------------ 4.1 Shipper shall pay for ail transportation service hereunder from the Date of Commencement in accordance with TransCanada's FS Toll Schedule, List of Tolls, and General Terms and Conditions set out in TransCanada's Transportation Tariff as the same may be amended or approved from time to time by the National Energy Board ("NEB"). 4.2 Shipper shall pay delivery pressure service hereunder from the Date of Commencement in accordance with TransCanada's FS Toll Schedule, List of Tolls and General Terms and Conditions set out in TransCanada's Transportation Tariff as the same may be amended or approved from time to time by the NEB. ARTICLE V - TERM OF CONTRACT - ---------------------------- 5.1 This Contract shall be effective from the date hereof and shall continue until the 31st day of October, 2009. ARTICLE VI - NOTICES - -------------------- 6.1 Any notice, request or demand ("Notice") to or upon the respective parties hereto shall be in writing and shall be validly communicated by the delivery thereof to its addressee, either personally or by courier, first class mail, or telecopier to the address hereinafter mentioned: IN THE CASE OF TRANSCANADA: TransCanada PipeLines Limited (i) mailing address: P.O. Box 1000 Station M Calgary, Alberta T2P 4K5 (ii) delivery address: TransCanada PipeLines Tower 111 - 5th Avenue S.W. Calgary, Alberta T2P 3Y6 Attention: Vice-President, Transportation Services & Rates Telecopy: (403) 267-8620 (iii) nominations: Attention: Supervisor, Gas Accounting Telecopy: (403) 267-6338/6339 (iv) invoices Attention: Manager, Revenue Accounting Telecopy: (403) 267-1074 (v) other matters: Attention: Vice-President, Transportation Services & Rates Telecopy: (403) 267-8620 IN THE CASE OF SHIPPER: Renaissance Energy Ltd. (i) mailing address: 3300, 400 - 3rd Avenue SW Calgary, Alberta T2P 4H2 (ii) delivery address: Same as above (iii) nominations: Attention: Coordinator, Transportation & Supply Telecopy: (403) 267-4811 (iv) invoices: Attention: Manager, Marketing Contracts & Operations Telecopy: (403) 267-4811 (v) other matters: Attention: Manager, Marketing Contracts & Operations Telecopy: (403) 267-4811 Any such Notice shall be sent in order to ensure prompt receipt of such Notice by the other party. Such Notice sent as aforesaid shall be deemed to have been received by the party to whom it is sent at the time of its delivery if personally delivered or if sent by telecopier, or on the day following transmittal thereof if sent by courier, or on the third day following the transmittal thereof if sent by first class mail; PROVIDED however, that, in the event normal mail service, courier service, or telecopier service shall be interrupted by a cause beyond the control of the parties hereto, then the party sending the Notice shall utilize any service that has not been so interrupted or shall deliver such Notice. Each party shall provide Notice to the other of any change of address for the purposes hereof. ARTICLE VII - MISCELLANEOUS PROVISIONS - -------------------------------------- 7.1 The FS Toll Schedule, the List of Tolls, and the General Terms and Conditions set out in TransCanada's Transportation Tariff as amended or approved from time to time by the NEB are all by reference made a part of this Contract and operations hereunder shall, in addition to the terms and conditions of this Contract, be subject to the provisions thereof. TransCanada shall notify Shipper at any time that TransCanada files with the NEB revisions to the FS Toll Schedule, the List of Tolls, and/or the General Terms and Conditions (the "Revisions") and shall provide Shipper with a copy of the Revisions. 7.2 The headings used throughout this Contract, the FS Toll Schedule, the List of Tolls, and the General Terms and Conditions are inserted for convenience of reference only and are not to be considered or taken into account in construing the terms or provisions thereof nor to be deemed in any way to quality, modify or explain the effect of any such provisions or terms. 7.3 This Contract shall be construed and applied, and be subject to the laws of the Province of Alberta, and, when applicable, the laws of Canada, and shall be subject to the rules, regulations and orders of any regulatory or legislative authority having jurisdiction. 7.4 All terms and words herein capitalized and not otherwise defined in this Contract are incorporated by reference into this Contract from the FS Toll Schedule, the List of Tolls, and the General Terms and Conditions set out in TransCanada's Transportation Tariff as amended from time to time. ARTICLE VIII - DELIVERY PRESSURE - -------------------------------- 8.1 TransCanada shall increase the line pressure of the gas it delivers to Shipper at the Delivery Point to a pressure of not less than 4 850 kPa (g). IN WITNESS WHEREOF, the parties hereto have executed this Contract as of the date first above written. TRANSCANADA PIPELINES LIMITED s/Steve Johnson per Vice President title s/ S.S.M. per title RENAISSANCE ENERGY LTD. s/Max Muselius per Vice President-Marketing title EXHIBIT "1" This is EXHIBIT "1" to the FIRM SERVICE CONTRACT for FIRM TRANSPORTATION SERVICE, made as of the 1st day of November, 1993 between TRANSCANADA PIPELINES LIMITED ("TransCanada") and RENAISSANCE ENERGY LTD. ("Shipper") The Delivery Point hereunder is the point of interconnection between the pipeline facilities of TransCanada and Tennessee Gas Pipeline Company which is located at: Niagara Falls, Ontario The Receipt Point hereunder is the point of interconnection between the pipeline facilities of TransCanada and NOVA Corporation of Alberta which is located at: Empress, Alberta To: TransCanada PipeLines Limited Attn: Ches Maciorowski Date: October 25, 1994 To Whom It May Concern: Attached are copies of Temporary Transportation Contract Assignments as follows; 1. Temporary Transportation Contract Assignment between New England Power Company (Assignor) and Renaissance Energy Ltd. (Assignee), dated October 28, 1993. 2. Temporary Transportation Contract Assignment between Renaissance Energy Ltd. (Assignor) and New England Power Company (Assignee), dated October 27, 1993. The purpose of these Assignments was to effect a swap of capacity held by New England Power Company to Waddington for capacity held by Renaissance to Niagara for the time period November 1, 1993 through November 1, 1994. The swap volume was 333.6 10 3m3. The purpose of this letter is to ask that TransCanada accept the request of New England Power Company and Renaissance Energy Ltd. to extend the period of the above outlined agreements from November 1, 1994 through November 1, 1995; and that the volume be changed from 333.6 10 3m3 to 333.9 10 3m3. Both parties to the assignments outlined above have signed here to signify to you their mutual agreement to the changes proposed in the immediately preceding paragraph. Please advise immediately if this letter agreement is sufficient to effect the charges outlined herein. Thank you. NEW ENGLAND POWER COMPANY RENAISSANCE ENERGY LTD. s/Jeffrey W. VanSant s/J.A. Curkan By: By: Manager, Marketing Authorized Signatory Contracts & Operations Title: Title: By: Title: October 26, 1994 Date: Date: EX-10 13 EXHIBIT 10(AA) Exhibit 10(aa) GAS TRANSPORTATION AGREEMENT Firm Transportation Service ---------------------------- (For New England Power Company) (Continued) EXHIBIT A RECEIPT AND DELIVERY POINTS TO THE GAS TRANSPORTATION AGREEMENT BETWEEN ALGONQUIN GAS TRANSMISSION COMPANY (TRANSPORTER) AND NEW ENGLAND POWER COMPANY (SHIPPER) DATED APRIL 15,1994 ------------- (Continued) Deliveries for the account of Shipper shall be made at each Point of Delivery in quantities not in excess of the Maximum Daily Delivery Obligation specified herein and at a pressure not less than the Minimum Delivery Pressure specified herein. Transporter' Maximum Daily Minimum Point(s) of Delivery Obligation Delivery Pressure Delivery (MMBtu) (1) Psig - ------------- ------------------- ---------------- Beginning on the later of (i) November 1, 1993 or (ii) the date on which all necessary facilities required to be constructed by Transporter and upstream domestic pipelines are completed and ready for service: Manchester, St. Meter Station Providence, RI 59,220 MMBtu 350 Interconnection between Algonquin's G-1 System and the Brayton Point Lateral in Dighton, MA 0 MMBtu - 801 Milford, MA Meter Station 0 MMBtu - GAS TRANSPORTATION AGREEMENT Firm Transportation Service --------------------------- (For New England Power Company) (Continued) EXHIBIT A RECEIPT AND DELIVERY POINTS TO THE GAS TRANSPORTATION AGREEMENT BETWEEN ALGONQUIN GAS TRANSMISSION COMPANY (TRANSPORTER) AND NEW ENGLAND POWER COMPANY (SHIPPER) DATED APRIL 15,1994 (Continued) Transporter's Maximum Daily Minimum Point(s) of Delivery Obligation Delivery Pressure Delivery (MMBtu) (1) Psig - ------------- --------------------- ----------------- Beginning on the later of (i) November 1, 1994 or (ii) the date that all necessary facilities required to be constructed by Transporter and upstream domestic pipelines are completed and ready for service: Manchester, St. Meter Station Providence, RI 94,214 MMBtu 350 Interconnection between Algonquin's G-1 System and the Brayton Point Lateral in Dighton, MA 0 MMBtu - 801 Milford, MA Meter Station 0 MMBtu - Signed for Identification s/ John J. Mullaney Algonquin: s/ Jeffrey W. VanSant s/ Jeffrey D. Tranen Shipper: Jeffrey W. VanSant Jeffrey D. Tranen Vice President President Supersedes Exhibit A of Contract Number 932002 Dated July 3, 1992. _______________ (1) The above Maximum Daily Receipt Obligation shall be equal to the total of Maximum Daily Delivery Obligation for each delivery point plus Transporter's allowed Fuel Reimbursement Quantity as may exist from time to time. EX-13 14 EXHIBIT 13 ANNUAL REPORT 1994 NEW ENGLAND POWER COMPANY A Subsidiary of New England Electric System [LOGO] New England Power A New England Electric System company NEW ENGLAND POWER COMPANY 25 Research Drive Westborough, Massachusetts 01582 Directors (As of December 31, 1994) Joan T. Bok John W. Newsham Chairman of the Board of New Executive Vice President of the Company England Electric System and Vice President of New England Electric System Frederic E. Greenman Vice President, General Counsel, John W. Rowe and Assistant Clerk of the Company Chairman of the Company and President and Senior Vice President, General and Chief Executive Officer of New Counsel, and Secretary of New England Electric System England Electric System Jeffrey D. Tranen Alfred D. Houston President of the Company and Vice Executive Vice President and Chief President of New England Electric System Financial Officer of New England Electric System Officers (As of December 31, 1994) John W. Rowe John F. Malley Chairman of the Company and Vice President President and Chief Executive Officer of New England Electric Arnold H. Turner System Vice President Jeffrey D. Tranen Jeffrey W. VanSant President of the Company and Vice Vice President President of New England Electric System Michael E. Jesanis Treasurer of the Company and of New John W. Newsham England Electric System Executive Vice President of the Company and Vice President of New Robert King Wulff England Electric System Clerk of the Company and of certain affiliates Lawrence E. Bailey Vice President John G. Cochrane Assistant Treasurer of the Company and Jeffrey A. Donahue of an affiliate Vice President Kirk L. Ramsauer Frederic E. Greenman Assistant Clerk of the Company and of an Vice President, General Counsel, and affiliate Assistant Clerk of the Company and Senior Vice President, General Howard W. McDowell Counsel, and Secretary of New Controller of the Company and of certain England Electric System affiliates Transfer Agent and Dividend Paying Agent of Preferred Stock Bank of Boston, Boston, Massachusetts Registrar of Preferred Stock State Street Bank and Trust Company, Boston, Massachusetts This report is not to be considered an offer to sell or buy or solicitation of an offer to sell or buy any security. NEW ENGLAND POWER COMPANY New England Power Company, a wholly-owned subsidiary of New England Electric System, is a Massachusetts corporation and is qualified to do business in Massachusetts, New Hampshire, Rhode Island, Connecticut, Maine, and Vermont. The Company is subject, for certain purposes, to the jurisdiction of the regulatory commissions of these six states, the Securities and Exchange Commission and the Federal Energy Regulatory Commission. The Company's business is principally that of generating, purchasing, transmitting, and selling electric energy in wholesale quantities to other electric utilities, principally its affiliates, Granite State Electric Company, Massachusetts Electric Company, and The Narragansett Electric Company. In 1994, 94 percent of the Company's revenue from the sale of electricity was derived from sales for resale to affiliated companies and 6 percent from sales for resale to municipal and other utilities. The Company, through its own generating units, entitlements and purchase power contracts, has a total capability of 5,533 megawatts. In 1994, the Company's energy mix was 37 percent coal, 19 percent nuclear, 16 percent gas, 12 percent hydro, 10 percent oil, and 6 percent renewable non-utility generation. The Company is a member of the New England Power Pool, which provides for the coordination of the planning and operation of the generation and transmission facilities in New England, and the region-wide central dispatch of generation. Report of Independent Accountants New England Power Company, Westborough, Massachusetts: We have audited the accompanying balance sheets of New England Power Company (the Company), a wholly-owned subsidiary of New England Electric System, as of December 31, 1994 and 1993 and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. Boston, Massachusetts COOPERS & LYBRAND L.L.P. February 27, 1995 NEW ENGLAND POWER COMPANY Financial Review Overview Net income increased by $8 million in 1994 compared with 1993, reflecting decreased purchased power charges excluding fuel, lower interest expense and increased allowance for funds used during construction. The decrease in purchased power was due to overhauls and refueling shutdowns of partially-owned nuclear power suppliers in 1993. In addition, earnings in 1993 were reduced by a one-time after-tax charge of $6 million ($10 million before tax) associated with an early retirement program. Partially offsetting these increases in 1994 earnings were increased operation and maintenance expenses and the reimbursement of certain power plant dismantlement costs through revenue credits to The Narragansett Electric Company (Narragansett), an affiliate. Net income increased by $7 million in 1993, primarily as a result of increased revenues attributable to increased peak-demands for electricity in the summer of 1993, lower costs of scheduled overhauls at thermal generating units in 1993, and reduced interest costs achieved through debt refinancings. The increased earnings were partially offset by the one-time charge in connection with the early retirement program discussed above as well as increases in operation and maintenance expenses. Rate Activity In February 1995, the Federal Energy Regulatory Commission (FERC) approved a rate agreement filed by the Company. Under the agreement, which is effective January 1995, the Company's base rates will be frozen until 1997. Before this rate agreement, the Company's rate structure contained two surcharges which were recovering the costs of a coal conversion project and a portion of the Company's investment in the Seabrook 1 nuclear unit (Seabrook 1). Under the rate agreement, these two surcharges, which were due to expire in mid-1995, will be rolled into base rates. The agreement also provides for the costs resulting from the Manchester Street Station repowering project, which is expected to be completed in late 1995, to be included in rate base, without a rate increase (see "Utility Plant Expenditures and Financings" section). In addition, the agreement allows the Company to recover approximately $50 million of deferred costs associated with terminated purchased power contracts and postretirement benefits other than pensions (PBOPs) over seven years. The agreement also provides for full current recovery of PBOP costs commencing in 1995. The agreement further provides for the recovery over three years of $27 million of costs related to the dismantling of a retired Narragansett generating station and the replacement of a turbine rotor at one of the Company's generating units. The agreement also increases the Company's recovery of depreciation expense by approximately $8 million annually to recognize costs associated with the eventual dismantling of its Brayton Point and Salem Harbor generating plants. Under the agreement, approximately $15 million of the $38 million in Seabrook 1 costs due to be recovered in 1995 pursuant to a 1988 settlement agreement will be deferred and recovered in 1996. The agreement further allows for deferral of additional purchased power contract termination costs and any increases in nuclear decommissioning payments for recovery in future rates. Yankee Atomic Electric Company, of which the Company is a 30 percent owner, recently announced a new decommissioning cost estimate, which, if approved by the FERC, would increase annual billings to the Company by $11 million, beginning in late 1995 and ending in July 2000. (See Note C-1 of the "Notes to Financial Statements" for a discussion of a 1995 shutdown of the Maine Yankee nuclear unit.) The settlement rates provide for approximately $24 million in revenues in 1996 to complete the amortization of pre-1988 Seabrook 1 costs and the costs associated with the cancelled Seabrook 2 nuclear unit. To the extent the settlement rates stay in effect beyond 1996, the agreement provides that these revenues be applied first to accelerate recovery of deferred PBOP costs, and then to additional amortization of the Company's investment in the Millstone 3 nuclear unit. Finally, the agreement provided that the Company would reimburse its wholesale customers for approximately $15 million of discounts provided by these customers under service extension discount programs. Under these programs, retail customers are entitled to such discounts only if they have signed an agreement not to purchase power from another supplier or generate any additional power themselves for a three to five year period. The FERC's approval of this rate agreement applies to all of the Company's customers except the Town of Norwood, Massachusetts and the Milford Power Limited Partnership (MPLP), who intervened in the rate case. A separate hearing will be conducted to determine the appropriate rate to charge these two parties, who represent less than 2 percent of the Company's sales. Operating Revenue The following table summarizes the changes in operating revenue: Increase (Decrease) in Operating Revenue ---------------------------------------- (In Millions) 1994 1993 - ------------- ---- ---- Sales growth $10 $17 Narragansett integrated facilities credit (excluding fuel) (6) 11 Rate changes - 3 Fuel recovery (6) (4) Accrued NEEI fuel revenues (7) (8) Other 1 (1) --- --- $(8) $18 === === The entire output of Narragansett's generating capacity is made available to the Company. Narragansett receives a credit on its purchased power bill from the Company for its fuel costs and other generation and transmission-related costs. The increased credit in 1994 reflects increased dismantlement costs being incurred on Narragansett's previously retired South Street generating facility. The decrease in the credit in 1993 shown in the table above reflects reduced non-fuel related credits due to the mid-1992 sale by Narragansett to the Company of 90 percent of its ownership interest in the Manchester Street Station (see "Utility Plant Expenditures and Financings" section). Accrued New England Energy Incorporated (NEEI) fuel revenues and accrued NEEI fuel costs (see "Operating Expenses" section) reflect losses incurred by NEEI, an affiliate of the Company, on its rate-regulated oil and gas operations. These revenues are accrued in the year of the loss but are billed to the Company's customers through its fuel adjustment clause in the following year. Changes in accrued NEEI fuel revenues and fuel costs are principally due to fluctuations in NEEI production (see "Fuel Supply" section). Operating Expenses The following table summarizes the changes in total operating expenses discussed below: Increase (Decrease) in Operating Expenses ----------------------------------------- (In Millions) 1994 1993 - ------------ ---- ---- Fuel costs $(7) $(3) Accrued NEEI fuel costs (7) (8) Purchased energy excluding fuel (11) (2) Other operation and maintenance 18 13 Depreciation and amortization 6 4 Taxes 5 15 --- --- $ 4 $19 === === Total fuel costs represent fuel for generation and the portion of purchased electric energy permitted to be recovered through the Company's fuel adjustment clause. Purchased energy excluding fuel represents the remainder of purchased electric energy costs. The 1994 decrease in purchased energy excluding fuel was primarily due to overhauls and refueling shutdowns of partially-owned nuclear power suppliers in 1993. The increase in other operation and maintenance expense in 1994 reflects increases in generating plant maintenance costs associated with overhauls of wholly-owned generating units in part to achieve compliance with the Clean Air Act. The increase also reflects cost increases in computer system development, increased demand-side management program expenses, and general increases in other areas. These increases were partially offset by a one-time charge in 1993 of $10 million associated with an early retirement program. The increase in other operation and maintenance expense in 1993 primarily reflects the previously mentioned early retirement program costs, $2 million associated with the adoption of a new accounting standard for postemployment benefits, increased computer systems development costs, and general increases in other areas. These increases were partially offset by an $8 million decrease in generating plant maintenance costs. The increases in depreciation and amortization expense in 1994 and 1993 primarily reflect increased amortization of Seabrook 1 as part of a 1988 rate settlement and increased depreciation on new plant expenditures. The increase in 1993 was partially offset by a decrease in depreciation as a result of new lower depreciation rates established in a prior rate case, which went into effect in March 1992. The increase in taxes in 1994 and 1993 primarily reflects increased income taxes and municipal property taxes. The increase in income taxes in 1993 also includes the effects of the 1993 increase in the federal income tax rate from 34 percent to 35 percent. Interest Expense The decreases in interest expense in 1994 and 1993 are primarily due to significant refinancings of corporate debt at lower interest rates during 1993 and 1992. In addition, the decrease in 1994 also reflects reduced interest on rate refunds and taxes primarily in the fourth quarter, partially offset by increased interest on short-term debt. Allowance for Funds Used During Construction (AFDC) AFDC increased in 1994 and 1993 due to increased construction work in progress associated with the repowering of the Manchester Street Station (see "Utility Plant Expenditures and Financings" section). Fuel Supply NEEI is engaged in domestic oil and gas exploration, development, and production. NEEI operates under an intercompany pricing policy (Pricing Policy) with the Company which was approved by the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935. The Pricing Policy requires the Company to purchase all fuel meeting its specifications offered to it by NEEI. Due to precipitate declines in oil and gas prices, NEEI has incurred operating losses since 1986, and expects to incur substantial additional losses in the future. These losses are being passed on to the Company under the Pricing Policy. The Company is allowed to recover these losses from its customers under the Company's 1988 FERC rate settlement, which covered all costs incurred by or resulting from commitments made by NEEI through March 1, 1988. Other subsequent costs incurred by NEEI are subject to normal regulatory review. Hazardous Waste The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. New England Electric System (NEES) subsidiaries currently have in place an environmental audit program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. The Company has been named as a potentially responsible party (PRP) by either the U.S. Environmental Protection Agency (EPA) or the Massachusetts Department of Environmental Protection for six sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The Company is currently aware of other sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. Where appropriate, the Company intends to seek recovery from its insurers and from other PRPs, but it is uncertain whether and to what extent such efforts would be successful. The Company believes that hazardous waste liabilities for all sites of which it is aware will not be material to its financial position. Electric and Magnetic Fields (EMF) In recent years, concerns have been raised about whether EMF, which occur near transmission and distribution lines as well as near household wiring and appliances, cause or contribute to adverse health effects. Numerous studies on the effects of these fields, some of them sponsored by electric utilities (including NEES companies), have been conducted and are continuing. Some of the studies have suggested associations between certain EMF and health effects, including various types of cancer, while other studies have not substantiated such associations. It is impossible to predict the ultimate impact on the Company and the electric utility industry if further investigations were to demonstrate that the present electricity delivery system is contributing to increased risk of cancer or other health problems. Many utilities, including the NEES companies, have been contacted by customers regarding a potential relationship between EMF and adverse health effects. To date, no court in the United States has ruled that EMF from electrical facilities cause adverse health effects and no utility has been found liable for personal injuries alleged to have been caused by EMF. In any event, the Company believes that it currently has adequate insurance coverage for personal injury claims. Several state courts have recognized a cause of action for damage to property values in transmission line condemnation cases based on the fear that power lines cause cancer. It is difficult to predict what the impact on the Company would be if this cause of action is recognized in the states in which the Company operates and in contexts other than condemnation cases. Legislation has been introduced in Massachusetts that, if passed, would require state agencies to study existing EMF-related research and make recommendations for further legislation. Clean Air Requirements Approximately 45 percent of the Company's electricity is produced at eight older thermal generating units in Massachusetts. Six are fueled by coal, one by oil, and one by oil and gas. The federal Clean Air Act requires significant reduction in utility sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions that result from burning fossil fuels by the year 2000 to reduce acid rain and ground-level ozone (smog). The Company is reducing SO2 emissions under Phase 1 of the federal acid rain program that became effective in 1995. The Company is also subject to Massachusetts SO2 and NOx reduction regulations taking effect in 1995. The SO2 and NOx reductions that are being made to meet 1995 Phase 1 requirements have resulted in one-time operation and maintenance costs of $16 million and capital costs of $88 million through December 31, 1994. Additional expenditures in 1995 are expected to be less than $10 million and $30 million, respectively. Depending on fuel prices, the Company also expects to incur up to $5 million annually in increased costs to purchase cleaner fuels to meet SO2 emission reduction requirements. All eight of the Company's thermal units will be subject to Phase 2 of the federal and state acid rain regulations that become effective in 2000. The Company believes that the SO2 controls already installed for the 1995 requirements will satisfy the Phase 2 acid rain regulations. In connection with the federal ozone emission requirements, state environmental agencies in ozone non-attainment areas are developing a second phase of NOx reduction regulations that would have to be fully implemented by the Company no later than 1999. While the exact costs are not known, the Company estimates that the cost of implementing these regulations would not jeopardize continued operation of its units. The generation of electricity from fossil fuel also emits trace amounts of certain hazardous air pollutants and fine particulates. An EPA study of utility hazardous air pollutant emissions will be completed in 1995. The study's conclusions could lead to new emission standards requiring costly controls or fuel restrictions on the Company's plants. At this time, NEES and its subsidiaries cannot estimate the impact the findings of this research might have on the Company's operations. Purchased Power Contract Dispute In October 1994, the Company was sued by Milford Power Limited Partnership (MPLP), a venture of Enron Corporation and Jones Capital that owns a 149 megawatt (MW) gas-fired power plant in Milford, Massachusetts. The Company purchases 56 percent of the power output of the facility under a long-term contract with MPLP. The suit alleges that the Company has engaged in a scheme to cause MPLP and its power plant to fail and has prevented MPLP from finding a long-term buyer for the remainder of the facility's output. The complaint includes allegations that the Company has violated the Federal Racketeer Influenced and Corrupt Organizations Act, engaged in unfair or deceptive acts in trade or commerce, and breached contracts. MPLP seeks compensatory damages in an unspecified amount, as well as treble damages. The Company believes that the allegations of wrongdoing are without merit. The Company has filed counterclaims and crossclaims against MPLP, Enron Corporation, and Jones Capital, seeking monetary damages and termination of the purchased power contract. MPLP also intervened in the Company's rate filing (see "Rate Activity" section). Competitive Conditions The electric utility business is being subjected to increasing competitive pressures, stemming from a combination of trends, including increasing electric rates, improved technologies, and new regulations and legislation intended to foster competition. To date, this competition has been most prominent in the bulk power market in which non-utility generating sources have noticeably increased their market share. For example, since non-utilities were allowed to enter the wholesale generation market, two-thirds of the Company's new generating capability has come from independent generating sources and Hydro-Quebec. Since 94 percent of the Company's revenues are from its affiliates that serve retail customers, the Company is affected by increased competition that these affiliates are facing in the retail market. Currently, retail competition includes competition with alternative fuel suppliers (including natural gas companies) for heating and cooling, competition with customer-owned generation to displace purchases from electric utilities, and direct competition among electric utilities to attract major new facilities to their service territories. Electric utilities, including the NEES companies, are under increasing pressure from large commercial and industrial customers to discount rates or face the possibility that such customers might relocate or seek alternate suppliers. Across the country, including the states serviced by the NEES companies, there have been an increasing number of proposals to allow retail customers to choose their electricity supplier, with utilities required to deliver that electricity over their transmission and distribution systems. In Massachusetts, the Massachusetts Division of Energy Resources (DOER) proposed in January 1995 that the Massachusetts Department of Public Utilities (MDPU) modify its regulations to allow retail utility customers to choose a supplier and bid for access to the local utility's transmission and distribution systems in situations where new generating capacity is needed. The NEES companies have indicated their support for the DOER proposal. The Company's Massachusetts retail affiliate has announced plans to propose a limited bidding experiment consistent with the DOER proposal. Also in Massachusetts, the MDPU initiated a proceeding in February 1995 regarding electric industry regulation and structure. In Rhode Island, the Rhode Island Public Utilities Commission has convened a task force of utilities, commercial and industrial customers, regulators, and other interested parties to prepare a report by May 1995 regarding restructuring the industry. In New Hampshire, the New Hampshire Public Utilities Commission is considering the proposal of a new company to sell electricity at retail to large customers in New Hampshire. The impact of increased customer choice on the financial condition of utilities is uncertain. In recent years, substantial surplus generating capacity in the Northeast has resulted in the sale of bulk power by utilities to other utilities at prices substantially below the total costs of owning and operating, or contracting for, such generating capacity. Should retail customers gain access to the bulk power market, particularly while surplus capacity exists, it is unlikely that utilities would be able to charge power prices which fully cover their costs. Such unrecovered costs, which could be substantial, have been referred to by the industry as stranded costs. Whether and to what extent utilities should be able to recover stranded costs resulting from increased customer choice has been the subject of much debate. In 1994, the FERC issued a notice of proposed rule-making on the recovery of stranded costs. The NEES companies and other utilities have taken the position that when a regulatory body changes policies which govern customer choice and the resultant rates paid by customers, utilities must be compensated for commitments made under the former policies. Furthermore, the utility industry believes that recovery of stranded costs is necessary to promote efficient competition among market participants. Previously, the FERC ruled in 1992, in a proceeding not involving NEES subsidiaries, that a utility may recover such stranded costs from a departing wholesale requirements customer. On appeal, the United States Court of Appeals for the District of Columbia Circuit has questioned whether allowing utilities to recover stranded costs is anti-competitive and the Court remanded the case back to the FERC for further proceedings and development of the competitive issues. In addition to the arguments described above, the NEES companies have taken the position that, because utility transmission and distribution assets have a replacement value in excess of their historic costs (on which utility rates are set), utilities should have the ability to recover stranded generation-related costs by realizing the higher value of transmission and distribution assets. The NEES companies have stated their willingness, in order to assure stranded cost recovery and promote increased competition, to consider divesting their transmission system, either through sale or spinoff. The NEES companies are actively responding to current and anticipated competitive pressures in a variety of ways, including cost control and a 1993 corporate reorganization into separate retail and wholesale business units. The wholesale business unit has responded to increased competition by freezing base rates until at least 1997 (wholesale base rates were last raised in March 1992), terminating certain purchased power and gas pipeline contracts, shutting down uneconomic generating stations, and accelerating the recovery of uneconomic assets and other deferred costs. In addition, the Company's wholesale tariff requires its wholesale customers, including NEES's retail subsidiaries, to provide seven years notice before they may terminate the tariff. The retail business unit's response to competition includes the EnergyFIT program, which offers comprehensive value-added services for large business customers, intensified business development efforts, including economic development rates and service packages to encourage businesses to locate in the retail companies' service territories, and development of new pricing and service options for customers. Additionally, more than 80 percent of the NEES companies' currently eligible large commercial and industrial customers have signed service extension discount contracts providing for discounts in exchange for agreements requiring three to five years notice before they may change electricity suppliers. As part of their long-term planning process, the NEES companies are from time to time evaluating other strategies, such as business combinations and other forms of restructuring, to better respond to the changing competitive environment. Electric utility rates are generally based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. These accounting rules require regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the income statement impact of certain costs that are expected to be recovered in future rates. The effects of competition could ultimately cause the operations of the Company, or a portion thereof, to cease meeting the criteria for application of these accounting rules. In such an event, accounting standards applicable to enterprises in general would apply and immediate write-off of any previously deferred costs (regulatory assets) would be necessary in the year in which these criteria were no longer applicable. In addition, if, because of competition, utilities are unable to recover all of their costs in rates, it may be necessary to write off those costs that are not recoverable. Utility Plant Expenditures and Financings Cash expenditures for utility plant totaled $229 million for 1994 including $142 million related to the Manchester Street Station repowering project discussed below. The funds necessary for utility plant expenditures during the period were provided by net cash from operating activities, after the payment of dividends, and proceeds of long-term and short-term debt issues. Cash expenditures for utility plant for 1995 are estimated to be $160 million (including $110 million related to the repowering of Manchester Street Station). Internally generated funds are estimated to provide 90 percent of the Company's 1995 capital expenditure requirements for utility plant. Cash expenditures for utility plant for 1995 are also expected to be funded through the issuance of long-term and short-term debt. In 1994, the Company issued $28 million of mortgage bonds at rates ranging from 8.10 percent to 8.53 percent. The Company has issued $25 million of long-term debt to date in 1995 at interest rates ranging from 7.40 percent to 7.94 percent. In addition, the Company has refinanced $10 million of variable rate mortgage bonds to date in 1995. The Company plans to issue an additional $25 million of long-term debt in 1995. The Company's major construction project is the repowering of Manchester Street Station, a 140 MW electric generating station in Providence, Rhode Island. Repowering will more than triple the power generation capacity of Manchester Street Station and substantially increase the plant's thermal efficiency. To facilitate financing this project, Narragansett sold a 90 percent interest in the existing station to the Company effective July 1, 1992. The total cost for the generating station, scheduled to be placed in service in late 1995, is estimated to be approximately $520 million, including AFDC. At December 31, 1994, $298 million, including AFDC, had been spent on the generating station ($270 million by the Company). In addition, related transmission improvements, which were principally the responsibility of Narragansett, were placed in service in September 1994 at a cost of approximately $60 million. Substantial commitments have been made relative to future planned expenditures for this project. At December 31, 1994, the Company had $146 million of short-term debt outstanding including $129 million in the form of commercial paper borrowings and $17 million of borrowings from affiliates. At December 31, 1994, the Company had lines of credit and bond purchase facilities with banks totaling $490 million which are available to provide liquidity support for commercial paper borrowings and for $342 million of the Company's outstanding variable rate mortgage bonds in tax-exempt commercial paper mode and for other corporate purposes. There were no borrowings under these lines of credit at December 31, 1994. March 22, 1995 NEW ENGLAND POWER COMPANY Statements of Income Year Ended December 31, (In Thousands) ------------------------------------ 1994 1993 1992 ---- ---- ---- Operating revenue, principally from affiliates $1,540,757 $1,549,014 $1,530,875 Operating expenses: Fuel for generation 260,540 273,347 288,868 Purchased electric energy 513,583 525,985 524,134 Other operation 196,610 186,087 162,134 Maintenance 110,528 103,261 114,210 Depreciation and amortization 137,979 131,932 127,733 Taxes, other than income taxes 54,400 51,931 50,828 Income taxes 96,596 93,997 79,799 ---------- ---------- ---------- Total operating expenses 1,370,236 1,366,540 1,347,706 ---------- ---------- ---------- Operating income 170,521 182,474 183,169 Other income: Allowance for equity funds used during construction 9,142 3,252 2,722 Equity in income of nuclear power companies 4,816 5,646 6,252 Other income (expense) - net, including related taxes (293) (566) 1,822 ---------- ---------- ---------- Operating and other income 184,186 190,806 193,965 ---------- ---------- ---------- Interest: Interest on long-term debt 38,711 45,837 59,382 Other interest 1,956 5,427 2,071 Allowance for borrowed funds used during construction - credit (5,854) (1,926) (1,639) ---------- ---------- ---------- Total interest 34,813 49,338 59,814 ---------- ---------- ---------- Net income $ 149,373 $ 141,468 $ 134,151 ========== ========== ========== Statements of Retained Earnings Year Ended December 31, (In Thousands) ------------------------------------ 1994 1993 1992 ---- ---- ---- Retained earnings at beginning of year $ 346,153 $ 321,699 $ 293,113 Net income 149,373 141,468 134,151 Dividends declared on cumulative preferred stock (3,440) (4,883) (5,591) Dividends declared on common stock, $18.50, $17.25, and $15.50 per share, respectively (119,323) (111,261) (99,974) Premium on redemption of preferred stock (870) ---------- ---------- ---------- Retained earnings at end of year $ 372,763 $ 346,153 $ 321,699 ========== ========== ========== The accompanying notes are an integral part of these financial statements. NEW ENGLAND POWER COMPANY Balance Sheets At December 31, (In Thousands) ------------------------ 1994 1993 ---- ---- Assets Utility plant, at original cost $2,524,544 $2,445,702 Less accumulated provisions for depreciation and amortization 1,001,393 943,750 ---------- ---------- 1,523,151 1,501,952 Net investment in Seabrook 1 under rate settlement (Note C-2) 38,283 103,344 Construction work in progress 314,777 165,860 ---------- ---------- Net utility plant 1,876,211 1,771,156 ---------- ---------- Investments: Nuclear power companies, at equity (Note C-1) 46,349 46,342 Non-utility property and other investments 22,980 19,927 ---------- ---------- Total investments 69,329 66,269 ---------- ---------- Current assets: Cash 377 610 Accounts receivable: Affiliated companies 197,655 201,674 Others 69,532 58,581 Fuel, materials, and supplies, at average cost 73,361 55,955 Prepaid and other current assets 33,729 26,454 ---------- ---------- Total current assets 374,654 343,274 ---------- ---------- Accrued Yankee Atomic costs (Note C-1) 122,452 103,501 Deferred charges and other assets (Note A-6) 170,192 157,087 ---------- ---------- $2,612,838 $2,441,287 ========== ========== Capitalization and Liabilities Capitalization: Common stock, par value $20 per share, authorized and outstanding 6,449,896 shares $ 128,998 $ 128,998 Premiums on capital stocks 86,829 86,829 Other paid-in capital 288,000 288,000 Retained earnings 372,763 346,153 ---------- ---------- Total common equity 876,590 849,980 Cumulative preferred stock, par value $100 per share (Note H) 60,516 61,028 Long-term debt 695,466 667,448 ---------- ---------- Total capitalization 1,632,572 1,578,456 ---------- ---------- Current liabilities: Short-term debt (including $16,575,000 and $8,325,000 to affiliates) 145,575 50,525 Accounts payable (including $69,089,000 and $58,056,000 to affiliates) 179,761 144,100 Accrued liabilities: Taxes 6,133 9,337 Interest 9,914 10,086 Other accrued expenses (Note A-7) 10,866 38,313 Dividends payable 14,512 ---------- ---------- Total current liabilities 352,249 266,873 ---------- ---------- Deferred federal and state income taxes 364,073 344,077 Unamortized investment tax credits 59,014 62,591 Accrued Yankee Atomic costs (Note C-1) 122,452 103,501 Other reserves and deferred credits 82,478 85,789 Commitments and contingencies (Note D) ---------- ---------- $2,612,838 $2,441,287 ========== ========== The accompanying notes are an integral part of these financial statements. NEW ENGLAND POWER COMPANY Statements of Cash Flows Year Ended December 31, (In Thousands) ------------------------------------ 1994 1993 1992 ---- ---- ---- Operating activities: Net income $ 149,373 $ 141,468 $ 134,151 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 142,764 135,746 130,562 Deferred income taxes and investment tax credits - net 23,051 20,665 6,378 Allowance for funds used during construction (14,996) (5,178) (4,361) Early retirement program 2,967 Decrease (increase) in accounts receivable (6,932) 31,323 120 Decrease (increase) in fuel, materials, and supplies (17,406) 16,902 (12,079) Decrease (increase) in prepaid and other current assets (7,275) (4,908) (15,938) Increase (decrease) in accounts payable 35,661 (35,913) 26,437 Increase (decrease) in other current liabilities (30,823) 25,205 (16,374) Other, net (26,845) (46,559) (4,995) --------- --------- --------- Net cash provided by operating activities $ 246,572 $ 281,718 $ 243,901 --------- --------- --------- Investing activities: Plant expenditures, excluding allowance for funds used during construction $(229,015) $(156,614) $(115,093) Other investing activities (3,053) (2,402) Purchase of 90 percent interest in Manchester Street Station from affiliate ( 3,249) --------- --------- --------- Net cash used in investing activities $(232,068) $(159,016) $(118,342) --------- --------- --------- Financing Activities: Dividends paid on common stock $(133,835) $(120,936) $ (75,787) Dividends paid on preferred stock (3,440) (4,883) (5,591) Changes in short-term debt 95,050 32,200 18,325 Long-term debt - issues 28,000 224,000 260,000 Long-term debt - retirements (224,000) (337,000) Preferred stock - retirements (512) (25,000) Premium on reacquisition of long-term debt (3,255) (12,294) Premium on redemption of preferred stock (870) --------- --------- --------- Net cash used in financing activities $ (14,737) $(122,744) $(152,347) --------- --------- --------- Net decrease in cash and cash equivalents $ (233) $ (42) $ (26,788) Cash and cash equivalents at beginning of year 610 652 27,440 --------- --------- --------- Cash and cash equivalents at end of year $ 377 $ 610 $ 652 ========= ========= ========= Supplementary Information: Interest paid less amounts capitalized $ 32,510 $ 42,390 $ 65,210 --------- --------- --------- Federal and state income taxes paid $ 83,455 $ 78,300 $ 65,484 --------- --------- --------- Dividends received from investments at equity $ 4,809 $ 5,103 $ 5,932 --------- --------- --------- The accompanying notes are an integral part of these financial statements. NEW ENGLAND POWER COMPANY Notes to Financial Statements Note A - Significant Accounting Policies - ---------------------------------------- 1. System of Accounts: The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by regulatory bodies having jurisdiction. 2. Allowance for Funds Used During Construction (AFDC): The Company capitalizes AFDC as part of construction costs. AFDC represents the composite interest and equity costs of capital funds used to finance that portion of construction costs not eligible for inclusion in rate base. In 1994, an average of $25 million of construction work in progress was included in rate base, all of which was attributable to the Manchester Street Station repowering project. AFDC is capitalized in "Utility plant" with offsetting non-cash credits to "Other income" and "Interest". This method is in accordance with an established rate-making practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFDC rates were 7.8 percent, 8.1 percent, and 9.7 percent in 1994, 1993, and 1992, respectively. 3. Depreciation and Amortization: The depreciation and amortization expense included in the statements of income is composed of the following: Year Ended December 31, (In Thousands) ------------------------------------ 1994 1993 1992 ---- ---- ---- Depreciation $ 52,834 $ 53,128 $ 55,858 Nuclear decommissioning costs (Note A-4) 1,951 1,951 1,890 Amortization: Investment in Seabrook 1 nuclear unit under rate settlement (Note C-2) 65,061 58,437 52,443 Oil Conservation Adjustment 11,854 12,137 11,263 Property losses 6,279 6,279 6,279 -------- -------- -------- Total depreciation and amortization expense $137,979 $131,932 $127,733 ======== ======== ======== Depreciation is provided annually on a straight-line basis. The provisions for depreciation (excluding nuclear decommissioning) as a percentage of weighted average depreciable property were 2.4 percent in 1994, 2.5 percent in 1993, and 2.7 percent in 1992. The Oil Conservation Adjustment is designed to recover expenditures for coal conversion facilities at the Company's Salem Harbor Station by 1995. At December 31, 1994, such unamortized coal conversion costs included in utility plant were $4,467,000. 4. Nuclear Plant Decommissioning and Nuclear Fuel Disposal: The Company is recovering its share of projected decommissioning costs for the Millstone 3 nuclear generating unit (Millstone 3) and the Seabrook 1 nuclear generating unit (Seabrook 1) through depreciation expense. The Company records decommissioning cost expense on its books consistent with its rate recovery. ln addition, the Company is paying its portion of projected decommissioning costs for all of the Yankee nuclear power companies NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note A - Significant Accounting Policies (continued) - ---------------------------------------- (Yankees) through purchased power expense. Such costs reflect estimates of total decommissioning costs approved by the Federal Energy Regulatory Commission (FERC). Each of the operating nuclear units in which the Company has an ownership interest has established decommissioning trust funds or escrow funds into which payments are being made to meet the projected costs of decommissioning its plant. If any of the units were shut down prior to the end of their operating licenses, the funds collected for decommissioning to that point would be insufficient. Listed below is information on each nuclear plant in which the Company has an ownership interest. (See Note C-1 for a discussion of Yankee Atomic nuclear power station decommissioning.) The Company's share of (in millions of dollars) ----------------------------------------------- Estimated Decommissioning Ownership Cost Fund License Unit Interest (in 1994 $) Balances** Expiration - ---- --------- --------------- ---------- ---------- Connecticut Yankee 15% 53 22 2007 Maine Yankee *** 20% 66 22 2008 Vermont Yankee 20% 66 23 2012 Millstone 3 * 12% 53 11 2025 Seabrook 1 * 10% 36 4 2026 * Fund balances are included in "Non-utility property and other investments" on the balance sheet and approximate market value. ** Certain additional amounts are anticipated to be available through tax deductions. *** A Maine statute provides that if both Maine Yankee and its decommissioning trust fund have insufficient assets to pay for the plant decommissioning, the owners of Maine Yankee are jointly and severally liable for the shortfall. In accordance with its recent rate agreement which became effective in 1995, the Company is allowed to defer for later recovery any increases in decommissioning payments over the level included in rates until its next rate filing becomes effective. There is no assurance that decommissioning costs actually incurred by the Yankees, Millstone 3, or Seabrook 1 will not substantially exceed these amounts. For example, decommissioning cost estimates assume the availability of permanent repositories for both low-level and high-level nuclear waste which do not currently exist. The Nuclear Waste Policy Act of 1982 establishes that the federal government is responsible for the disposal of spent nuclear fuel. The federal government requires the Company to pay a fee based on its share of the net generation from the Millstone 3 and Seabrook 1 nuclear units. The Company is recovering this fee through its fuel clause. Similar costs are incurred by Connecticut Yankee, Maine Yankee, and Vermont Yankee. These costs are billed to the Company and recovered from customers through the Company's fuel clause. 5. Cash: The Company classifies short-term investments with a remaining maturity of 90 days or less as cash. Current banking arrangements do not require outstanding checks to be funded until actually presented for payment. NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note A - Significant Accounting Policies (continued) - ---------------------------------------- Outstanding checks are therefore recorded in accounts payable until such time as the banks present them for payment. 6. Deferred Charges and Other Assets: The components of deferred charges and other assets are as follows: At December 31, (In Thousands) --------------------- 1994 1993 ---- ---- Regulatory assets: Deferred SFAS No. 109 costs (see Note B) $ 34,482 $ 41,114 Unamortized losses on reacquired debt 34,862 37,107 Purchased power termination costs 29,012 28,400 Deferred gas pipeline charges (see Note D-4) 37,562 13,187 Unamortized property losses 7,373 12,745 Deferred SFAS No. 106 costs (see Note E-2) 19,149 10,538 Other 2,542 8,928 -------- -------- 164,982 152,019 Other deferred charges and other assets 5,210 5,068 -------- -------- $170,192 $157,087 ======== ======== Electric utility rates are generally based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. These accounting rules require regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the income statement impact of certain costs that are expected to be recovered in future rates. The effects of competition could ultimately cause the operations of the Company, or a portion thereof, to cease meeting the criteria for application of these accounting rules. In such an event, accounting standards applicable to enterprises in general would apply and immediate write-off of any previously deferred costs (regulatory assets) would be necessary in the year in which these criteria were no longer applicable. Approximately $100 million of the regulatory assets at December 31, 1994 listed above are expected to be recovered within 10 years, with the majority of the remaining balance to be recovered within the following 20 years. The only items for which the majority of the balance shown above will not be recovered within the next 10 years are the deferred SFAS No. 109 costs and the deferred gas pipeline charges. 7. Other Accrued Expenses: The components of other accrued expenses are as follows: At December 31, (In Thousands) --------------------- 1994 1993 ---- ---- Accrued wages and benefits $ 6,397 $10,619 Capital lease obligations due within one year 4,324 4,151 Accrued purchased power termination costs 21,900 Other 145 1,643 ------- ------- $10,866 $38,313 ======= ======= NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note B - Income Taxes - --------------------- The Company and other subsidiaries participate with New England Electric System (NEES) in filing consolidated federal income tax returns. The Company's income tax provision is calculated on a separate return basis. Federal income tax returns have been examined and reported on by the Internal Revenue Service through 1991. Total income taxes in the statements of income are as follows: Year Ended December 31, (In Thousands) --------------------------- 1994 1993 1992 ---- ---- ---- Income taxes charged to operations $96,596 $93,997 $79,799 Income taxes charged (credited) to "Other income" (994) 838 2,627 ------- ------- ------- Total income taxes $95,602 $94,835 $82,426 ======= ======= ======= Total income taxes, as shown above, consist of the following components: Year Ended December 31, (In Thousands) --------------------------- 1994 1993 1992 ---- ---- ---- Current income taxes $72,551 $74,171 $76,048 Deferred income taxes 26,628 23,270 7,706 Investment tax credits--net (3,577) (2,606) (1,328) ------- ------- ------- Total income taxes $95,602 $94,835 $82,426 ======= ======= ======= Investment tax credits are deferred and amortized over the estimated lives of the property giving rise to the credits. Since the Tax Reform Act of 1986 generally eliminated investment tax credits, the amounts shown above principally reflect the amortization of investment tax credits generated in prior years. Total income taxes, as shown above, consist of federal and state components as follows: Year Ended December 31, (In Thousands) --------------------------- 1994 1993 1992 ---- ---- ---- Federal income taxes $78,274 $77,593 $67,830 State income taxes 17,328 17,242 14,596 ------- ------- ------- Total income taxes $95,602 $94,835 $82,426 ======= ======= ======= With regulatory approval of the FERC, the Company has adopted comprehensive interperiod tax allocation (normalization) for temporary book/tax differences. NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note B - Income Taxes - (continued) - --------------------- Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows: Year Ended December 31, (In Thousands) --------------------------- 1994 1993 1992 ---- ---- ---- Computed tax at statutory rate $85,741 $82,706 $73,636 Increases (reductions) in tax resulting from: Amortization of investment tax credits (3,045) (2,511) (3,210) State income taxes, net of federal income tax benefit 11,263 10,770 9,634 All other differences 1,643 3,870 2,366 ------- ------- ------- Total income taxes $95,602 $94,835 $82,426 ======= ======= ======= The Financial Accounting Standards Board established Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes" which became effective in 1993. The application of this new standard did not have a significant impact on 1993 or 1994 net income. The following table identifies the major components of total deferred income taxes: At December 31, (In Millions) --------------------- 1994 1993 ---- ---- Deferred tax asset: Plant related $ 96 $ 86 Investment tax credits 25 26 All other 29 39 ----- ----- 150 151 ----- ----- Deferred tax liability: Plant related (384) (373) Equity AFDC (47) (48) All other (83) (74) ----- ----- (514) (495) ----- ----- Net deferred tax liability $(364) $(344) ===== ===== There were no valuation allowances for deferred tax assets deemed necessary. The deferred taxes resulting from timing differences which appeared on the income statement in 1992 (prior to the adoption of SFAS No. 109 in 1993) primarily included deferred income taxes of $12 million related to utility plant and $5 million related to losses on reacquired debt, partially offset by deferred tax credits related to Seabrook 2 property losses of $5 million and rate adjustment mechanisms of $6 million. NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note C - Nuclear Power Investments - ---------------------------------- 1. Yankee Nuclear Power Companies: The Company has minority interests in the four Yankees. These ownership interests are accounted for on the equity method. The Company's share of the expenses of the Yankee units is accounted for on the "Purchased electric energy" line on the statements of income. A summary of combined results of operations, assets and liabilities of the four Yankees is as follows: (In Thousands) ------------------------------------ 1994 1993 1992 ---- ---- ---- Operating revenue $ 631,940 $ 700,148 $ 684,775 ========== ========== ========== Net income $ 30,345 $ 30,061 $ 35,298 ========== ========== ========== Company's equity in net income $ 4,816 $ 5,646 $ 6,252 ========== ========== ========== Net plant 537,103 591,650 666,685 Other assets 1,458,186 1,286,923 1,221,905 Liabilities and debt (1,748,960) (1,633,139) (1,644,962) ---------- ---------- ---------- Net assets $ 246,329 $ 245,434 $ 243,628 ========== ========== ========== Company's equity in net assets $ 46,349 $ 46,342 $ 45,799 ========== ========== ========== Company's purchased electric energy $ 106,404 $ 118,362 $ 118,465 ========== ========== ========== At December 31, 1994, $12 million of undistributed earnings of the nuclear power companies were included in the Company's retained earnings. The Company has a 30 percent ownership interest in Yankee Atomic, which owns a 185 megawatt (MW) nuclear generating station in Rowe, Massachusetts. The station began commercial service in 1960. At December 31, 1994, the Company's investment in Yankee Atomic was approximately $7 million. In February 1992, the Yankee Atomic board of directors decided to permanently cease power operation of, and in time decommission, the facility. In March 1993, the FERC approved a settlement agreement that allows Yankee Atomic to recover all but $3 million of its approximately $50 million remaining investment in the plant over the period extending to July 2000, when the plant's Nuclear Regulatory Commission (NRC) operating license would have expired. Yankee Atomic recorded the $3 million before-tax write-down in 1992. The settlement agreement also allows Yankee Atomic to earn a return on the unrecovered balance during the recovery period and to recover other costs, including an increased level of decommissioning costs, over this same period. Decommissioning cost recovery increased from $6 million per year to $27 million per year for the period 1993 to 1995. In the fourth quarter of 1994, Yankee announced a new decommissioning cost estimate that, subject to approval by the FERC, would increase billings to the Company by an additional $11 million per year through July 2000. The Company has recorded an estimate of its entire future payment obligations to Yankee Atomic as a liability on its balance sheet and an offsetting regulatory asset reflecting its expected future rate recovery of such costs. This liability and related regulatory asset amounted to approximately $122 million each at December 31, 1994, and are included on separate lines on the balance sheet. NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note C - Nuclear Power Investments (continued) - ---------------------------------- The Company has a 20 percent ownership interest in Maine Yankee which owns an 880 MW nuclear generating station in Wiscasset, Maine. Since January 1995, the station has been shut down for refueling and inspection. On the basis of preliminary results of testing and analysis performed during this shutdown, Maine Yankee has detected substantially greater deterioration of its steam generator tubes than had been previously found and is unable to predict its effect on the future of the unit. 2. Jointly-Owned Nuclear Generating Units: The Company is also a 12 percent and 10 percent owner, respectively, of the Millstone 3 and Seabrook 1 nuclear generating units, each 1,150 MW. The Company's net investment in Millstone 3, included in "Net utility plant" is approximately $400 million. The Company's rate recovery of its investment in Seabrook 1 was resolved through two separate rate settlement agreements. A portion of the Company's pre-1988 investment is being recovered in base rates over a period of seven and one-half years ending in mid-1995. Under the Company's rate agreement, that was recently approved by the FERC, approximately $15 million of the $38 million in Seabrook 1 costs due to be recovered in 1995 pursuant to a 1988 settlement agreement will be deferred and recovered in 1996. This investment, net of amortization, is shown on a separate line on the balance sheets. The Company's net investment in Seabrook 1 since January 1, 1988, which amounts to approximately $43 million at December 31, 1994, is included in "Net utility plant" on the balance sheet and is being recovered over 37 years. The Company's share of the related expenses for Millstone 3 and Seabrook 1 is included in the operating expenses of the Company's income statements. Note D - Commitments and Contingencies - -------------------------------------- 1. Oil and Gas Operations: New England Energy Incorporated (NEEI), a subsidiary of NEES, is engaged in domestic oil and gas exploration, development, and production. NEEI operates under an intercompany pricing policy (Pricing Policy) with the Company approved by the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935. The Pricing Policy requires the Company to purchase all fuel meeting its specifications offered to it by NEEI. Under the Pricing Policy, NEEI's oil and gas exploration program is composed of prospects entered into through December 31, 1983 under a rate-regulated program. NEEI has incurred operating losses since 1986, due to precipitate declines in oil and gas prices, and expects to incur substantial additional losses in the future. These losses are passed on to the Company in the year after they are incurred by NEEI and, in turn, are being recovered from customers through the Company's fuel clause. The Company's ability to pass such losses on to its customers was favorably resolved in the Company's 1988 FERC rate settlement. This settlement covered all costs incurred by or resulting from commitments made by NEEI through March 1, 1988. In 1994, 1993, and 1992, the Company recorded accrued fuel expenses and accrued revenues of $40 million, $46 million, and $55 million, respectively, representing losses incurred by NEEI in each year. Under the settlement, certain NEEI costs incurred subsequent to March 1, 1988 are subject to normal regulatory review. NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note D - Commitments and Contingencies (continued) - -------------------------------------- 2. Plant Expenditures: The Company's utility plant expenditures are estimated to be $160 million in 1995. At December 31, 1994, substantial commitments had been made relative to future planned expenditures. 3. Hydro-Quebec Interconnection: The Company is a participant in both the Hydro-Quebec Phase I and Phase II projects. The Company's participation percentage in both projects is approximately 18 percent. The Hydro-Quebec Phase I and Phase II projects were established to transmit power from Hydro-Quebec to New England. Three affiliates of the Company were created to construct and operate transmission facilities related to these projects. The participants, including the Company, have entered into support agreements that end in 2020, to pay monthly their proportionate share of the total cost of constructing, owning, and operating the transmission facilities. The Company accounts for these support agreements as capital leases and accordingly recorded approximately $78 million in utility plant at December 31, 1994. Under the support agreements, the Company has agreed, in conjunction with any Hydro-Quebec Phase II project debt financing, to guarantee its share of project debt. At December 31, 1994, the Company had guaranteed approximately $32 million. 4. Natural Gas Pipeline Capacity: In connection with the Company's efforts to reduce sulfur dioxide emissions and repower generating units, the Company has signed several contracts for natural gas pipeline capacity and gas supply. These agreements require minimum fixed payments. The Company's minimum net payments are currently estimated to be approximately $65 million in 1995 and $70 million per year during 1996 to 1999. As part of a rate settlement, the Company is recovering 50 percent of the fixed pipeline capacity payments through its current fuel clause and deferring the recovery of the remaining 50 percent until the Manchester Street repowering project is completed. The Company has deferred payments of approximately $38 million as of December 31, 1994 (see Note A-6). The Company has been using a portion of this capacity to sell natural gas. Proceeds from the sale of natural gas and pipeline capacity of $55 million, $21 million, and $3 million in 1994, 1993, and 1992, respectively, have been passed to customers through the Company's fuel clause. These proceeds have been included on the fuel for generation line in the Company's statements of income as an offset to the related fuel expense. 5. Hazardous Waste: The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. The NEES subsidiaries currently have in place an environmental audit program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. The Company has been named as a potentially responsible party (PRP) by either the U.S. Environmental Protection Agency or the Massachusetts Department of Environmental Protection for six sites at which hazardous NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note D - Commitments and Contingencies (continued) - -------------------------------------- waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The Company is currently aware of other sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. Where appropriate, the Company intends to seek recovery from its insurers and from other PRPs, but it is uncertain whether and to what extent such efforts would be successful. The Company believes that hazardous waste liabilities for all sites of which it is aware will not be material to its financial position. 6. Nuclear Insurance: The Price-Anderson Act limits the amount of liability claims that would have to be paid in the event of a single incident at a nuclear plant to $8.9 billion (based upon 110 licensed reactors). The maximum amount of commercially available insurance coverage to pay such claims is only $200 million. The remaining $8.7 billion would be provided by an assessment of up to $79.3 million per incident levied on each of the nuclear units in the United States, subject to a maximum assessment of $ 10 million per incident per nuclear unit in any year. The maximum assessment, which was most recently calculated in 1993, is to be adjusted at least every five years to reflect inflationary changes. The Company's current interest in the Yankees (excluding Yankee Atomic), Millstone 3, and Seabrook 1 would subject the Company to a $58.0 million maximum assessment per incident. The Company's payment of any such assessment would be limited to a maximum of $7.3 million per incident per year. As a result of the permanent cessation of power operation of the Yankee Atomic plant, Yankee Atomic has received from the NRC a partial exemption from obligations under the Price-Anderson Act. However, Yankee Atomic must continue to maintain $100 million of commercially available nuclear insurance coverage. Each of the nuclear units in which the Company has an ownership interest also carries nuclear insurance to cover the costs of property damage, decontamination or premature decommissioning and workers' claims resulting from a nuclear incident. These policies may require additional premium assessments if losses relating to nuclear incidents at units covered by this insurance occurring in a prior six year period exceed the accumulated funds available. The Company's maximum potential exposure for these assessments, either directly, or indirectly through purchased power payments to the Yankees, is approximately $17 million per year. 7. Long-term Contracts for the Purchase of Electricity: The Company purchases a portion of its electricity requirements pursuant to long-term contracts with owners of various generating units. These contracts expire in various years from 1995 to 2029. Certain of these contracts require the Company to make minimum fixed payments, even when the supplier is unable to deliver power, to cover the Company's proportionate share of the capital and fixed operating costs of these generating units. The majority of the payments under these contracts are to the Yankees (excluding Yankee Atomic--see Note C-1) and Ocean State Power, entities in which the Company or its affiliates hold ownership interests. NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note D - Commitments and Contingencies (continued) - -------------------------------------- The fixed portion of payments under these contracts totaled $190 million in 1994 and $220 million in 1993 and 1992. These contracts have minimum fixed payment requirements of $215 million in 1995, $195 million in 1996, $190 million in 1997 and 1998, $185 million in 1999, and approximately $2 billion thereafter. The Company's other contracts, principally with non-utility generators, require the Company to make payments only if power supply capacity and energy are deliverable from such suppliers. The Company's payments under these contracts amounted to $210 million in 1994 and 1993 and $200 million in 1992. 8. Purchased Power Contract Dispute: In October 1994, the Company was sued by Milford Power Limited Partnership (MPLP), a venture of Enron Corporation and Jones Capital that owns a 149 MW gas-fired power plant in Milford, Massachusetts. The Company purchases 56 percent of the power output of the facility under a long-term contract with MPLP. The suit alleges that the Company has engaged in a scheme to cause MPLP and its power plant to fail and has prevented MPLP from finding a long-term buyer for the remainder of the facility's output. The complaint includes allegations that the Company has violated the Federal Racketeer Influenced and Corrupt Organizations Act, engaged in unfair or deceptive acts in trade or commerce, and breached contracts. MPLP seeks compensatory damages in an unspecified amount, as well as treble damages. The Company believes that the allegations of wrongdoing are without merit. The Company has filed counterclaims and crossclaims against MPLP, Enron Corporation, and Jones Capital, seeking monetary damages and termination of the purchased power contract. MPLP also intervened in the Company's recent rate filing. Note E - Employee Benefits - -------------------------- 1. Pension Plans: The Company participates with other subsidiaries of NEES in noncontributory defined-benefit plans covering substantially all employees of the Company. The plans provide pension benefits based on the employee's compensation during the five years before retirement. The Company's funding policy is to contribute each year, the net periodic pension cost for that year. However, the contribution for any year will not be less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note E - Employee Benefits (continued) - -------------------------- Net pension cost for 1994, 1993, and 1992 included the following components: Year Ended December 31, (In Thousands) --------------------------- 1994 1993 1992 ---- ---- ---- Service cost--benefits earned during the period $ 2,202 $ 1,953 $ 1,858 Plus (less): Interest cost on projected benefit obligation 6,403 6,070 5,558 Return on plan assets at expected long-term rate (6,554) (5,850) (5,600) Amortization 557 47 31 ------- ------- ------- Net pension cost $ 2,608 $ 2,220 $ 1,847 ======= ======= ======= Assumptions used to determine pension cost: Discount rate 7.25% 8.25% 8.50% Average rate of increase in future compensation levels 4.35% 5.35% 6.70% Expected long-term rate of return on assets 8.75% 8.75% 9.00% ------- ------- ------- Actual return on plan assets $ 608 $ 8,949 $ 4,887 ======= ======= ======= Service cost for 1993 does not reflect costs incurred in connection with an early retirement program offered by the Company in that year (see Note E-3). The funded status of the plans cannot be presented separately for the Company as the Company participates in the plans with other NEES subsidiaries. The following table sets forth the funded status of the NEES companies' plans at December 31: NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note E - Employee Benefits (continued) - -------------------------- Retirement Plans, (In Millions) --------------------------- 1994 1993 ---- ---- Union Non-Union Union Non-Union Employee Employee Employee Employee Plans Plans Plans Plans -------- --------- -------- --------- Benefits earned Actuarial present value of accumulated benefit liability: Vested $251 $308 $251 $333 Non-vested 8 9 20 6 ---- ---- ---- ---- Total $259 $317 $271 $339 ==== ==== ==== ==== Reconciliation of funded status Actuarial present value of projected benefit liability $303 $355 $310 $383 Unrecognized prior service costs (8) (4) (8) (6) SFAS No. 87 transition liability not yet recognized (amortized) - (1) - (1) Net loss not yet recognized (amortized) (13) (33) (11) (45) Additional minimum liability recognized - - - 8 ---- ---- ---- ---- 282 317 291 339 ---- ---- ---- ---- Pension fund assets at fair value 293 323 302 318 SFAS No. 87 transition asset not yet recognized (amortized) (13) - (14) - ---- ---- ---- ---- 280 323 288 318 ---- ---- ---- ---- Accrued pension/(prepaid) payments recorded on books $ 2 $ (6) $ 3 $ 21 ==== ==== ==== ==== The assumed discount rate and the assumed average rate of increase in future compensation levels used to calculate pension cost changed effective January 1, 1995 to 8.25 percent and 4.63 percent, respectively. The expected long-term rate of return on assets used to calculate pension cost was not changed from the level shown in the table above. The plans' funded status at December 31, 1994 was calculated using these revised rates. Plan assets are composed primarily of corporate equity, guaranteed investment contracts, debt securities, and cash equivalents. 2. Postretirement Benefit Plans Other Than Pensions and Postemployment Benefits: In 1993, SFAS No. 106, "Employer's Accounting for Postretirement Benefits Other Than Pensions" (PBOPs) went into effect. The Company provides health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage. NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note E - Employee Benefits (continued) - -------------------------- The total cost of PBOPs for 1994 and 1993 included the following components: Year Ended December 31, (In Thousands) --------------------- 1994 1993 ---- ---- Service cost--benefits earned during the period $1,628 $1,632 Plus (less): Interest cost on the accumulated benefit obligation 3,954 4,275 Return on plan assets at expected long-term rate (1,111) (725) Amortization 2,591 2,558 ------ ------ Net postretirement benefit cost $7,062 $7,740 ====== ====== Actual return on plan assets $ 54 $ 746 ====== ====== The following table sets forth benefits earned and the plans' funded status: At December 31, (In Millions) --------------------- 1994 1993 ---- ---- Accumulated postretirement benefit obligation: Retirees $ 31 $ 34 Fully eligible active plan participants 3 1 Other active plan participants 17 22 ---- ---- Total benefits earned 51 57 Unrecognized transition obligation (46) (49) Net gain (loss) not yet recognized 6 (1) ---- ---- 11 7 Plan assets at fair value 15 12 ---- ---- Prepaid postretirement benefit costs recorded on books $ 4 $ 5 ==== ==== 1995 1994 1993 ---- ---- ---- Assumptions used to determine postretirement benefit cost: Discount rate 8.25% 7.25% 8.25% Expected long-term rate of return on assets 8.50% 8.50% 8.50% Health care cost rate - 1994 and 1993 - 11.00% 12.00% Health care cost rate - 1995 to 2004 8.50% 8.50% 9.50% Health care cost rate - 2005 and beyond 6.25% 6.25% 7.25% NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note E - Employee Benefits (continued) - -------------------------- The plans' funded status at December 31, 1994 and 1993 presented above was calculated using the assumed rates in effect for 1995 and 1994, respectively. The health care cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed rates by 1 percent in each year would increase the accumulated postretirement benefit obligation as of December 31, 1994 by approximately $8 million and the net periodic cost for the year 1994 by approximately $1 million. The Company funds the annual tax deductible contributions. Plan assets are invested in equity and debt securities and cash equivalents. Prior to 1993, the Company recorded the cost of PBOPs when paid which amounted to approximately $1.7 million in 1992. The Company has deferred all increased costs that have resulted from the adoption of SFAS No. 106 in 1993. Pursuant to a recently approved rate agreement, recovery of PBOP costs on a current basis and recovery of $19 million of previously deferred amounts over a seven year period commenced January 1, 1995. Therefore adoption of this new accounting standard did not have a significant impact on net income. 3. 1993 Early Retirement and Special Severance Programs: In February 1993, the Company offered a voluntary early retirement program to non-union employees who were at least 55 years old with 10 years of service. This program was part of an organizational review with the goal of streamlining operations and reducing the work force. The early retirement offer was accepted by 43 employees. A special severance program was also announced in February 1993 for employees affected by the organizational review, but who were not eligible for, or did not accept, the early retirement offer. The Company recorded a one-time charge to 1993 earnings of approximately $6 million, after tax ($10 million, before tax), to reflect the cost of the early retirement and special severance programs which consisted principally of pension benefits. This total includes the Company's portion of its affiliated service company's cost of these programs. Note F - Short-term Borrowing Arrangements - ------------------------------------------ At December 31, 1994, the Company had $146 million of short-term debt outstanding including $129 million in the form of commercial paper borrowings and $17 million of borrowings of borrowings from affiliates. At December 31, 1994, the Company had lines of credit and standby bond purchase facilities with banks totaling $490 million which are available to provide liquidity support for commercial paper borrowings and for $342 million of the Company's outstanding variable rate mortgage bonds in tax-exempt commercial paper mode (see Note I) and for other corporate purposes. There were no borrowings under these lines of credit at December 31, 1994. Fees are paid on the lines and facilities in lieu of compensating balances. The weighted average rate on outstanding short-term borrowings was 6.0 percent at December 31, 1994. Note G - Intercompany Lending Arrangement - ----------------------------------------- NEES and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies which invest in the pool share the interest earned on NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note G - Intercompany Lending Arrangement (continued) - ----------------------------------------- a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice. Note H - Cumulative Preferred Stock - ----------------------------------- A summary of cumulative preferred stock at December 31, 1994 and 1993 is as follows (in thousands of dollars except for share data): Shares Authorized and Dividends Call Outstanding Amount Declared Price ------------- ------------- ------------- ------ 1994 1993 1994 1993 1994 1993 ---- ---- ---- ---- ---- ---- $100 Par value-- 6.00% Series 75,020 80,140 $ 7,502 $ 8,014 $ 458 $ 481 (a) 4.56% Series 100,000 100,000 10,000 10,000 456 456 $104.08 4.60% Series 80,140 80,140 8,014 8,014 368 368 101.00 4.64% Series 100,000 100,000 10,000 10,000 464 464 102.56 6.08% Series 100,000 100,000 10,000 10,000 608 608 102.34 7.24% Series 150,000 150,000 15,000 15,000 1,086 1,086 103.06 8.40% Series 840 8.68% Series 580 ------- ------- ------- ------- ------ ------ Total 605,160 610,280 $60,516 $61,028 $3,440 $4,883 ======= ======= ======= ======= ====== ====== (a) Noncallable. The annual dividend requirement for total cumulative preferred stock was $3,433,000 and $3,463,000 for 1994 and 1993, respectively. During 1993, all of the Company's 8.68 percent Series and 8.40 percent Series of cumulative preferred stock were redeemed. Total premiums of $870,000 in connection with these redemptions were charged to retained earnings in 1993. There are no mandatory redemption provisions on the Company's cumulative preferred stock. NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note I - Long-term Debt - ----------------------- A summary of long-term debt is as follows: At December 31, (In Thousands) ------------------------------ Series Rate % Maturity 1994 1993 - ------ ------ -------- ---- ---- General and Refunding Mortgage Bonds: W (93-3) 5.12 February 2, 1996 $ 5,000 $ 5,000 W (93-8) 5.06 February 5, 1996 5,000 5,000 Y (94-3) 8.10 December 22, 1997 3,000 W (93-2) 6.17 February 2, 1998 4,300 4,300 W (93-4) 6.14 February 2, 1998 1,300 1,300 W (93-5) 6.17 February 3, 1998 5,000 5,000 W (93-7) 6.10 February 4, 1998 10,000 10,000 W (93-9) 6.04 February 4, 1998 29,400 29,400 Y (94-4) 8.28 December 21, 1999 10,000 W (93-6) 6.58 February 10, 2000 5,000 5,000 W (93-1) 7.00 February 3, 2003 25,000 25,000 Y (94-2) 8.33 November 8, 2004 10,000 K 7.25 October 15, 2015 38,500 38,500 L 7.80 April 1, 2016 29,850 29,850 X variable March 1, 2018 79,250 79,250 R variable November 1, 2020 107,850 107,850 S variable November 1, 2020 20,750 20,750 T variable November 1, 2020 28,000 28,000 U 8.00 August 1, 2022 170,000 170,000 V variable October 1, 2022 106,150 106,150 Y (94-1) 8.53 September 20, 2024 5,000 Unamortized discounts and premiums (2,884) (2,902) -------- -------- Long-term debt $695,466 $667,448 ======== ======== Substantially all of the properties and franchises of the Company are subject to the lien of the mortgage indentures under which the general and refunding mortgage bonds have been issued. The Company will make cash payments of $10 million in 1996, $3 million in 1997, $50 million in 1998, and $10 million in 1999 to retire maturing mortgage bonds. There are no cash payments for maturing mortgage bonds required in 1995. The terms of $342 million of variable rate pollution control revenue bonds collateralized by the Company's mortgage bonds require the Company to reacquire the bonds under certain limited circumstances. At December 31, 1994, interest rates on the Company's variable rate bonds ranged from 3.30 percent to 5.60 percent. Note J - Fair Value of Financial Instruments - -------------------------------------------- At December 31, 1994, the Company's long-term debt had a carrying value of $695,000,000 and had a fair value of approximately $685,000,000. To estimate fair value, the carrying amount was used for debt that reprices frequently at market rates because the carrying amount is a reasonable estimate of fair value. For all other debt, the fair market value of the Company's long-term debt was estimated based on the quoted prices for similar issues or on the current rates offered to the Company for debt of the same remaining maturity. The fair value of the Company's short-term debt equals carrying value. The fair value of the Company's other investments equals carrying value. NEW ENGLAND POWER COMPANY Notes to Financial Statements (continued) Note K - Restrictions on Retained Earnings Available for Dividends on Common Stock - -------------------------------------------------------- Pursuant to the provisions of the Articles of Organization and the By-Laws relating to the Dividend Series Preferred Stock, certain restrictions on payment of dividends on common stock would come into effect if the "junior stock equity" was, or by reason of payment of such dividends became, less than 25 percent of "Total capitalization." However, the junior stock equity at December 31, 1994 was 54 percent of total capitalization including long-term debt due in one year and, accordingly, none of the Company's retained earnings at December 31, 1994 were restricted as to dividends on common stock under the foregoing provisions. Under restrictions contained in the indentures relating to general and refunding mortgage bonds, none of the Company's retained earnings at December 31, 1994 were restricted as to dividends on common stock. Note L - Supplementary Income Statement Information - --------------------------------------------------- Advertising expenses, expenditures for research and development, and rents were not material and there were no royalties paid. Taxes, other than income taxes, charged to operating expenses are set forth by classes as follows: Year Ended December 31, (In Thousands) ----------------------------- 1994 1993 1992 ---- ---- ---- Municipal property taxes $46,506 $44,124 $43,124 Federal and state payroll and other taxes 7,894 7,807 7,704 ------- ------- ------- $54,400 $51,931 $50,828 ======= ======= ======= New England Power Service Company, an affiliated service company operating pursuant to the provisions of Section 13 of the Public Utility Holding Company Act of 1935, furnished services to the Company at the cost of such services. These costs amounted to $103,961,000, $94,366,000, and $80,535,000, including capitalized construction costs of $22,396,000, $20,335,000, and $22,759,000, for each of the years 1994, 1993, and 1992, respectively. NEW ENGLAND POWER COMPANY Operating Statistics (Unaudited)
Year Ended December 31, ----------------------- 1994 1993 1992 1991 1990 ---- ---- ---- ---- ---- Sources of Energy (Thousands of KWH) Net generation - thermal 10,971,319 11,621,038 12,087,775 13,569,122 13,333,413 Net generation - conventional hydro 1,352,600 1,253,925 1,212,155 1,507,656 1,887,521 Generation - pumped storage 525,653 548,358 530,796 498,895 511,175 Net generation - nuclear 1,767,959 1,696,677 1,592,340 1,033,332 1,415,029 Nuclear entitlements 2,535,534 2,196,998 2,214,976 2,713,947 1,945,459 Purchased energy from non-affiliates (B) 8,674,191 7,800,975 7,287,856 6,323,144 5,128,451 Energy for pumping (723,352) (750,784) (738,364) (685,659) (699,473) ---------- ---------- ---------- ---------- ---------- Total generated and purchased 25,103,904 24,367,187 24,187,534 24,960,437 23,521,575 Losses, company use, etc. (635,695) (548,228) (632,850) (589,001) (557,978) ---------- ---------- ---------- ---------- ---------- Total sources of energy 24,468,209 23,818,959 23,554,684 24,371,436 22,963,597 ========== ========== ========== ========== ========== Sales of Energy (Thousands of KWH) Resale: Affiliated companies 22,182,761 21,858,491 21,497,993 21,496,098 21,706,432 Less - generation by affiliated Company (A) (5,781) (4,506) (83,753) (162,844) (583,413) ---------- ---------- ---------- ---------- ---------- Net sales to affiliated companies 22,176,980 21,853,985 21,414,240 21,333,254 21,123,019 Other utilities (B) 1,731,225 1,528,686 1,705,591 2,613,034 1,421,325 Municipals 551,866 426,525 415,659 411,171 404,352 ---------- ---------- ---------- ---------- ---------- Total sales for resale 24,460,071 23,809,196 23,535,490 24,357,459 22,948,696 Ultimate customers 8,138 9,763 19,194 13,977 14,901 ---------- ---------- ---------- ---------- ---------- Total sales of energy 24,468,209 23,818,959 23,554,684 24,371,436 22,963,597 ========== ========== ========== ========== ==========
NEW ENGLAND POWER COMPANY Operating Statistics (Unaudited) (continued)
Year Ended December 31, ----------------------- 1994 1993 1992 1991 1990 ---- ---- ---- ---- ---- Operating Revenue (In Thousands) Revenue from electric sales Resale: Affiliated companies $1,448,503 $1,459,619 $1,450,831 $1,384,222 $1,281,933 Less - G and T credits (A) (32,346) (26,001) (38,697) (50,961) (66,048) ---------- ---------- ---------- ---------- ---------- Net sales to affiliated companies 1,416,157 1,433,618 1,412,134 1,333,261 1,215,885 Other utilities (B) 56,306 52,695 55,156 76,162 66,971 Municipals 32,055 27,574 26,980 25,755 22,989 ---------- ---------- ---------- ---------- ---------- Total revenue from sales for resale 1,504,518 1,513,887 1,494,270 1,435,178 1,305,845 Ultimate customers 606 752 1,399 1,097 1,033 ---------- ---------- ---------- ---------- ---------- Total revenue from electric sales 1,505,124 1,514,639 1,495,669 1,436,275 1,306,878 Other operating revenue 35,633 34,375 35,206 36,016 35,196 ---------- ---------- ---------- ---------- ---------- Total operating revenue $1,540,757 $1,549,014 $1,530,875 $1,472,291 $1,342,074 ========== ========== ========== ========== ========== Annual Maximum Demand (Kw - one hour peak) 4,385,000 4,081,000 3,964,000 4,250,000 4,059,000 (A) The generation and transmission facilities of affiliates are operated as an integrated part of the Company's power supply and the affiliates receive generation and transmission (G and T) credits against their power bills for costs of facilities so integrated. (B) Includes transactions with the New England Power Pool.
NEW ENGLAND POWER COMPANY Selected Financial Information Year Ended December 31, (In Millions) ------------------------------------- 1994 1993 1992 1991 1990 ---- ---- ---- ---- ---- Operating revenue: Electric sales (excluding fuel cost recovery) $ 942 $ 939 $ 907 $ 861 $ 809 Fuel cost recovery 563 576 589 575 498 Other 36 34 35 36 35 ------ ------ ------ ------ ------ Total operating revenue $1,541 $1,549 $1,531 $1,472 $1,342 Net income $ 149 $ 141 $ 134 $ 135 $ 222* Total assets $2,613 $2,441 $2,387 $2,277 $2,306 Capitalization: Common equity $ 877 $ 850 $ 825 $ 797 $ 784 Cumulative preferred stock 61 61 86 86 86 Long-term debt 695 667 666 730 781 ------ ------ ------ ------ ------ Total capitalization $1,633 $1,578 $1,577 $1,613 $1,651 Preferred dividends declared $ 3 $ 5 $ 6 $ 6 $ 6 Common dividends declared $ 119 $ 111 $ 100 $ 116 $ 105 * Includes the reversal of a portion of a 1988 write-down under a rate settlement related to the Seabrook 1 nuclear power plant. See Note C-2. Selected Quarterly Financial Information (Unaudited) First Second Third Fourth (In Thousands) Quarter Quarter Quarter Quarter - -------------- ------- ------- ------- ------- 1994 Operating revenue $399,574 $356,488 $419,555 $365,140 Operating income $ 56,873 $ 32,192 $ 55,217 $ 26,239 Net income $ 49,189 $ 26,182 $ 49,818 $ 24,184 1993 Operating revenue $395,065 $361,131 $417,912 $374,906 Operating income $ 51,579 $ 35,864 $ 56,625 $ 38,406 Net income $ 40,090 $ 26,944 $ 47,072 $ 27,362 Per share data is not relevant because the Company's common stock is wholly-owned by New England Electric System. A copy of New England Power Company's Annual Report on Form 10-K to the Securities and Exchange Commission, for the year ended December 31, 1994, will be available on or about April 1, 1995, without charge, upon written request to New England Power Company, Shareholder Services Department, 25 Research Drive, Westborough, Massachusetts 01582. EX-24 15 EXHIBIT 24 POWER OF ATTORNEY Each of the undersigned directors of New England Power Company (the "Company"), individually as a director of the Company, hereby constitutes and appoints John G. Cochrane, Thomas F. Killeen, and Geraldine M. Zipser, individually, as attorney-in-fact to execute on behalf of the undersigned the Company's annual report on Form 10-K for the year ended December 31, 1994, to be filed with the Securities and Exchange Commission, and to execute any appropriate amendment or amendments thereto as may be required by law. Dated this 21st day of March, 1995. s/ Joan T. Bok s/ John W. Newsham Joan T. Bok John W. Newsham s/ Frederic E. Greenman Frederic E. Greenman John W. Rowe s/ Alfred D. Houston s/ Jeffrey D. Tranen Alfred D. Houston Jeffrey D. Tranen EX-27 16 EXHIBIT 27 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT 1,000 DEC-31-1994 DEC-31-1993 DEC-31-1994 DEC-31-1993 12-MOS 12-MOS PER-BOOK PER-BOOK 1,876,211 1,771,156 69,329 66,269 374,654 343,274 292,644 260,588 0 0 2,612,838 2,441,287 128,998 128,998 374,829 374,829 372,763 346,153 876,590 849,980 0 0 60,516 61,028 695,466 667,448 145,575 50,525 0 0 0 0 0 0 0 0 0 0 0 0 834,691 812,306 2,612,838 2,441,287 1,540,757 1,549,014 96,596 93,997 1,273,640 1,272,543 1,370,236 1,366,540 170,521 182,474 13,665 8,332 184,186 190,806 34,813 49,338 149,373 141,468 3,440 4,883 145,933 135,715 119,323 111,261 38,711 45,837 246,572 281,718 0 0 0 0 Total deferred charges includes other assets and accrued Yankee Atomic costs. Short-term notes includes commercial paper obligations and short-term debt to affiliates. EX-13 17 EXHIBIT 13 ANNUAL REPORT 1994 MASSACHUSETTS ELECTRIC COMPANY A Subsidiary of New England Electric System [LOGO] Massachusetts Electric A New England Electric System company MASSACHUSETTS ELECTRIC COMPANY 25 Research Drive Westborough, Massachusetts 01582 Directors (As of December 31, 1994) Urville J. Beaumont Patricia McGovern Treasurer and Director, Beaumont Of Counsel, Goulston and Storrs, P.C., and Campbell, P.A. (Attorneys), Boston, Massachusetts Salem, New Hampshire John F. Reilly Joan T. Bok President and Chief Executive Officer Chairman of the Board of New of Fred C. Church, Inc., Lowell, England Electric System Massachusetts Sally L. Collins John W. Rowe Director--Workplace Health Services, President and Chief Executive Officer Greenfield, Massachusetts of New England Electric System John H. Dickson Richard P. Sergel President and Chief Executive Chairman of the Company and Vice Officer of the Company President of New England Electric System Charles B. Housen Chairman and President, Erving Richard M. Shribman Industries, Erving, Massachusetts Treasurer, Norick Realty Corporation, Salem, Massachusetts Dr. Kathryn A. McCarthy Research Professor of Physics, Roslyn M. Watson Tufts University, Medford, President, Watson Ventures, Boston, Massachusetts Massachusetts Officers (As of December 31, 1994) Richard P. Sergel Anthony C. Pini Chairman of the Company and Vice President Vice President of New England Electric System Nancy H. Sala Vice President John H. Dickson President and Chief Executive Dennis E. Snay Officer Vice President David L. Holt Michael E. Jesanis Executive Vice President Treasurer of the Company and of New England Electric System John C. Amoroso Vice President Robert King Wulff Clerk of the Company and of certain Peter H. Gibson affiliates Vice President Howard W. McDowell Gregory A. Hale Controller and Assistant Treasurer of Vice President the Company and Controller of certain affiliates Cheryl A. LaFleur Vice President Frederic E. Greenman Assistant Clerk and General Counsel of Robert H. McLaren the Company and Senior Vice President, Vice President General Counsel, and Secretary of New England Electric System Charles H. Moser Vice President Lydia M. Pastuszek Vice President of the Company and President of an affiliate Transfer Agent, Dividend Paying Agent, and Registrar of Preferred Stock State Street Bank and Trust Company, Boston, Massachusetts This report is not to be considered an offer to sell or buy or solicitation of an offer to sell or buy any security. MASSACHUSETTS ELECTRIC COMPANY Massachusetts Electric Company is a wholly-owned subsidiary of New England Electric System operating in Massachusetts. The Company's business is the distribution and sale of electricity at retail. Electric service is provided to approximately 940,000 customers in 149 cities and towns having a population of about 2,160,000 (1990 Census). The Company's service area covers approximately 43 percent of Massachusetts. The cities and towns served by the Company include the highly diversified commercial and industrial cities of Worcester, Lowell, and Quincy, the Interstate 495 high technology belt, suburban communities, and many rural towns. The principal industries served include computer manufacturing and related businesses, electrical and industrial machinery, plastic goods, fabricated metals and paper, and chemical products. In addition, a broad range of professional, banking, medical, and educational institutions is served. The properties of the Company consist principally of substations and distribution lines interconnected with transmission and other facilities of New England Power Company (NEP), an affiliate. The Company buys its electric energy requirements from NEP under a contract which obligates NEP to furnish such requirements at its standard resale rate. The Company participates through NEP in the New England Power Pool, which provides for the coordination of the planning and operation of the generation and transmission facilities in New England, and the region-wide central dispatch of generation. Report of Independent Accountants Massachusetts Electric Company, Westborough, Massachusetts: We have audited the accompanying balance sheets of Massachusetts Electric Company (the Company), a wholly-owned subsidiary of New England Electric System, as of December 31, 1994 and 1993 and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. Boston, Massachusetts COOPERS & LYBRAND L.L.P. February 27, 1995 MASSACHUSETTS ELECTRIC COMPANY Financial Review Overview Net income for 1994 increased by $11 million compared with 1993. The increase was primarily due to the inclusion in 1993 of one-time charges associated with an early retirement program and the establishment of additional gas waste reserves. In addition, the increase in 1994 earnings reflects increased kilowatthour (KWH) sales. These factors were partially offset by increased operation and maintenance expenses excluding the effect of the one-time charges discussed above. Net income decreased in 1993 by $11 million compared with 1992 primarily due to the 1993 one-time charges mentioned above. The Company also experienced an increase in purchased power expense due to increased peak-demand billings. This decrease was partially offset by a $45.6 million October 1992 rate increase, the effects of a 1993 rate agreement, and an increase in KWH sales billed to ultimate customers. Rate Activity On March 15, 1995, the Company filed a request with the Massachusetts Department of Public Utilities (MDPU) to increase its base rates by $62 million, effective October 1, 1995. As an alternative to this proposed increase, the Company filed an incentive rate plan which would increase rates by about $30 million effective October 1, 1995. Under the proposed incentive rate plan, subsequent base rate adjustments could occur annually on May 1 and would be based on a comparison of the Company's rates to rates of all electric utilities in Massachusetts. The Company is the first electric utility in the state to file under the MDPU's incentive ratemaking guidelines issued in February 1995. The Company also proposed a new discount program for large industrial customers that are willing to make a minimum annual usage commitment for a period of five years. The discounts would range from 5 percent to 12.5 percent of base rates depending on a customer's level of commitment. The Company expects an MDPU decision on its filing in late September 1995. In 1993, the MDPU approved a rate agreement filed by the Company, the Massachusetts Attorney General, and two groups of large commercial and industrial customers. Under the agreement, effective December 1, 1993, the Company implemented an 11 month general rate decrease of $26 million (annual basis). This rate reduction continued in effect through October 31, 1994, at which time rates increased to the previously approved levels. The Company also agreed not to further increase its base rates before October 1, 1995. The agreement also provided for the recognition of unbilled revenues for accounting purposes. Unbilled revenues at September 30, 1993 of approximately $35 million were amortized to income over 13 months commencing December 1993. The agreement further provided for rate discounts for large commercial and industrial customers who signed agreements to give a five-year notice to the Company before they purchase power from another supplier or generate any additional power themselves. The notice provision may be reduced from five to three years under certain conditions. The aggregate amount of these service extension discounts was $4 million during 1994 but will increase in 1995 to approximately $10 million per year under the terms of the agreement. Customers representing approximately 88 percent of revenue from currently eligible large commercial and industrial customers have signed these agreements. The discounts are currently available to customers with average monthly peak demands over 500 kilowatts. However, as part of its March 1995 rate filing with the MDPU, the Company proposed expanding this program to customers with average monthly peak demands over 200 kilowatts. In addition, commencing in 1995 the cost of these discounts is being passed on to New England Power Company (NEP), the Company's affiliated wholesale power supplier. This is the result of a NEP rate settlement that was approved by the Federal Energy Regulatory Commission (FERC) in early 1995. The 1993 agreement also resolved all rate recovery issues associated with environmental remediation costs of Massachusetts manufactured gas waste sites formerly owned by the Company and its affiliates, as well as certain other environmental cleanup costs (see "Hazardous Waste" section). Lastly, the agreement provided for the rate recovery of $8 million of certain storm restoration and other costs previously charged to expense. The deferral of these expenses increased 1993 fourth quarter earnings. Effective October 1992, the MDPU authorized a $45.6 million annual increase in rates for the Company. Demand-Side Management The Company regularly files its demand-side management (DSM) programs with the MDPU and has received approval to recover DSM program expenditures in rates on a current basis. These expenditures were $59 million, $47 million, and $44 million in 1994, 1993, and 1992, respectively. Since 1990, the Company has been allowed to earn incentives based on the results of its DSM programs. The Company must be able to demonstrate the electricity savings produced by its DSM programs to the MDPU before incentives are recorded. The Company recorded before-tax incentives of $7.1 million, $6.7 million, and $8.6 million in 1994, 1993, and 1992, respectively. The Company has received regulatory orders that will give it the opportunity to continue to earn incentives based on 1995 DSM program results. Operating Revenue The following table summarizes the changes in operating revenue: Increase (Decrease) in Operating Revenue ---------------------------------------- (In Millions) 1994 1993 - ------------- ---- ---- Sales growth $ 12 $10 General rate changes (22) 33 Unbilled revenues 21 11 Purchased power cost adjustment (PPCA) mechanism 7 (6) DSM recovery 12 2 Fuel recovery (16) 6 ---- ---- $ 14 $56 ==== ==== KWH sales increased by 1.8 percent in 1994 compared with a 0.9 percent increase in 1993. The increase in KWH sales in 1994 reflects an improved economy. The Company's rates contain a fuel clause and a PPCA provision. These mechanisms are designed to allow the Company to pass on to its customers changes in purchased energy costs resulting from rate increases or decreases by NEP, the Company's affiliated wholesale power supplier. General rate changes in 1994 reflect an 11 month rate decrease which went into effect on December 1, 1993. The agreement also provided for the recognition of unbilled revenues. For a further discussion, see the "Rate Activity" section. General rate changes in 1993 reflect general rate increases which went into effect in October 1992. Operating Expenses The following table summarizes the changes in total operating expenses discussed below: Increase (Decrease) in Operating Expenses ----------------------------------------- (In Millions) 1994 1993 - ------------ ---- ---- Purchased electric energy: Fuel costs $(16) $ 6 NEP refunds 4 1 Purchases and demand charges from NEP 4 9 Other operation and maintenance: DSM 11 4 Other (17) 48 Depreciation 2 2 Taxes 13 (5) ---- ---- $ 1 $65 ==== ==== The changes in fuel costs in 1994 and 1993 are the result of changes in the amount of New England Energy Incorporated (NEEI) costs passed through by NEP. NEEI is an affiliated company involved in oil and gas exploration and development. The 1994 decrease also reflects a reduction in the fuel component of NEP's purchased electric energy costs. In addition, the increase in fuel costs in 1993 reflects increased KWH purchases. The changes in other operation and maintenance expense in 1994 and 1993 are primarily the result of 1993 one-time charges of $26 million for the establishment of additional gas waste reserves and $13 million associated with an early retirement program, partially offset by the effects in the fourth quarter of 1993 of the Company's rate agreement which allowed recovery of amounts previously charged to expense (see "Rate Activity" section). Other operation and maintenance expense in 1994 and 1993 also included increased computer system development costs, increased postretirement benefit expenses, and general increases in other areas. The increase in 1993 also included increased uninsured claims and increased costs associated with the adoption of a new accounting standard for postemployment benefits. The increase in taxes in 1994 was primarily due to increased income and increased municipal property tax accruals. Hazardous Waste The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. New England Electric System (NEES) subsidiaries currently have in place an environmental audit program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. The Company has been named as a potentially responsible party (PRP) by either the U.S. Environmental Protection Agency or the Massachusetts Department of Environmental Protection for 17 sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The most prevalent types of hazardous waste sites with which the Company has been associated are manufactured gas locations. The Company is aware of approximately 35 such locations in Massachusetts (including seven of the 17 locations for which the Company is a PRP). The Company is currently aware of other sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. In 1993, the MDPU approved a rate agreement filed by the Company (see "Rate Activity" section) that allows for remediation costs of former manufactured gas sites and certain other hazardous waste sites located in Massachusetts to be met from a non-rate recoverable interest-bearing fund of $30 million established on the Company's books. Rate recoverable contributions of $3 million, adjusted for inflation, are added to the fund annually in accordance with the agreement. Any shortfalls in the fund would be paid by the Company and be recovered through rates over seven years. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. Where appropriate, the Company intends to seek recovery from its insurers and from other PRPs, but it is uncertain whether and to what extent such efforts would be successful. At December 31, 1994, the Company had total reserves for environmental response costs of $35 million and a related regulatory asset of $9 million. The Company believes that hazardous waste liabilities for all sites of which it is aware, and which are not covered by a rate agreement, will not be material to its financial position. Electric and Magnetic Fields (EMF) In recent years, concerns have been raised about whether EMF, which occur near transmission and distribution lines as well as near household wiring and appliances, cause or contribute to adverse health effects. Numerous studies on the effects of these fields, some of them sponsored by electric utilities (including NEES companies), have been conducted and are continuing. Some of the studies have suggested associations between certain EMF and health effects, including various types of cancer, while other studies have not substantiated such associations. It is impossible to predict the ultimate impact on the Company and the electric utility industry if further investigations were to demonstrate that the present electricity delivery system is contributing to increased risk of cancer or other health problems. Many utilities, including the NEES companies, have been contacted by customers regarding a potential relationship between EMF and adverse health effects. To date, no court in the United States has ruled that EMF from electrical facilities cause adverse health effects and no utility has been found liable for personal injuries alleged to have been caused by EMF. In any event, the Company believes that it currently has adequate insurance coverage for personal injury claims. Several state courts have recognized a cause of action for damage to property values in transmission line condemnation cases based on the fear that power lines cause cancer. It is difficult to predict what the impact on the Company would be if this cause of action is recognized in Massachusetts and in contexts other than condemnation cases. Legislation has been introduced in Massachusetts that, if passed, would require state agencies to study existing EMF-related research and make recommendations for further legislation. Competitive Conditions The electric utility business is being subjected to increasing competitive pressures, stemming from a combination of trends, including increasing electric rates, improved technologies, and new regulations and legislation intended to foster competition. To date, this competition has been most prominent in the bulk power market in which non-utility generating sources have noticeably increased their market share. For example, since non-utilities were allowed to enter the wholesale generation market, two-thirds of NEP's new generating capability has come from independent generating sources and Hydro-Quebec. Electric utilities are also facing increased competition in the retail market. Currently, retail competition includes competition with alternative fuel suppliers (including natural gas companies) for heating and cooling, competition with customer-owned generation to displace purchases from electric utilities, and direct competition among electric utilities to attract major new facilities to their service territories. Electric utilities, including the Company, are under increasing pressure from large commercial and industrial customers to discount rates or face the possibility that such customers might relocate or seek alternate suppliers. Across the country, including Massachusetts and the other states in which the Company's affiliates operate, there have been an increasing number of proposals to allow retail customers to choose their electricity supplier, with utilities required to deliver that electricity over their transmission and distribution systems. The Massachusetts Division of Energy Resources (DOER) proposed in January 1995 that the MDPU modify its regulations to allow retail utility customers to choose a supplier and bid for access to the local utility's transmission and distribution systems in situations where new generating capacity is needed. The NEES companies have indicated their support for the DOER proposal. The Company has announced plans to propose a limited bidding experiment consistent with the DOER proposal. In addition, the MDPU initiated a proceeding in February 1995 regarding electric industry regulation and structure. In Rhode Island, the Rhode Island Public Utilities Commission has convened a task force of utilities, commercial and industrial customers, regulators, and other interested parties to prepare a report by May 1995 regarding restructuring the industry. In New Hampshire, the New Hampshire Public Utilities Commission is considering the proposal of a new company to sell electricity at retail to large customers in New Hampshire. The impact of increased customer choice on the financial condition of utilities is uncertain. In recent years, substantial surplus generating capacity in the Northeast has resulted in the sale of bulk power by utilities to other utilities at prices substantially below the total costs of owning and operating, or contracting for, such generating capacity. Should retail customers gain access to the bulk power market, particularly while surplus capacity exists, it is unlikely that utilities would be able to charge power prices which fully cover their costs. Such unrecovered costs, which could be substantial, have been referred to by the industry as stranded costs. Whether and to what extent utilities should be able to recover stranded costs resulting from increased customer choice has been the subject of much debate. In 1994, the FERC issued a notice of proposed rule-making on the recovery of stranded costs. The NEES companies and other utilities have taken the position that when a regulatory body changes policies which govern customer choice and the resultant rates paid by customers, utilities must be compensated for commitments made under the former policies. Furthermore, the utility industry believes that recovery of stranded costs is necessary to promote efficient competition among market participants. Previously, the FERC ruled in 1992, in a proceeding not involving NEES subsidiaries, that a utility may recover such stranded costs from a departing wholesale requirements customer. On appeal, the United States Court of Appeals for the District of Columbia Circuit has questioned whether allowing utilities to recover stranded costs is anti-competitive and the Court remanded the case back to the FERC for further proceedings and development of the competitive issues. In addition to the arguments described above, the NEES companies have taken the position that, because utility transmission and distribution assets have a replacement value in excess of their historic costs (on which utility rates are set), utilities should have the ability to recover stranded generation-related costs by realizing the higher value of transmission and distribution assets. The NEES companies have stated their willingness, in order to assure stranded cost recovery and promote increased competition, to consider divesting their transmission system, either through sale or spinoff. The NEES companies are actively responding to current and anticipated competitive pressures in a variety of ways, including cost control and a 1993 corporate reorganization into separate retail and wholesale business units. The retail business unit, which includes the Company, is responding to competition through the development of an EnergyFIT program, which offers comprehensive value-added services for large business customers, intensified business development efforts, including economic development rates and service packages to encourage businesses to locate in the Company's service territory, and development of new pricing and service options for customers. Additionally, customers representing approximately 88 percent of the Company's currently eligible revenues have signed service extension discount contracts providing for discounts in exchange for agreements requiring three to five years notice before they may change electricity suppliers (see "Rate Activity" section). As part of their long-term planning process, the NEES companies are from time to time evaluating other strategies, such as business combinations and other forms of restructuring, to better respond to the changing competitive environment. Since the largest component of the Company's costs is represented by the cost of power purchased from NEP, its competitive position is affected by NEP's ability to control costs. NEP is controlling costs and positioning itself for increased competition by freezing base rates until at least 1997 (wholesale base rates were last raised in March 1992), terminating certain purchased power and gas pipeline contracts, shutting down uneconomic generating stations, and accelerating the recovery of uneconomic assets and other deferred costs. In addition, NEP's wholesale tariff requires its wholesale customers, including the Company and NEES's other retail subsidiaries, to provide seven years notice before they may terminate the tariff. Electric utility rates are generally based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. These accounting rules require regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the income statement impact of certain costs that are expected to be recovered in future rates. The effects of competition could ultimately cause the operations of the Company, or a portion thereof, to cease meeting the criteria for application of these accounting rules. In such an event, accounting standards applicable to enterprises in general would apply and immediate write-off of any previously deferred costs (regulatory assets) would be necessary in the year in which these criteria were no longer applicable. In addition, if, because of competition, utilities are unable to recover all of their costs in rates, it may be necessary to write off those costs that are not recoverable. Utility Plant Expenditures and Financings Cash expenditures for utility plant totaled $94 million in 1994. The funds necessary for utility plant expenditures during 1994 were primarily provided by net cash from operating activities, after the payment of dividends, and long-term and short-term debt issues. Cash expenditures for utility plant for 1995 are estimated to be approximately $105 million. Internally generated funds are expected to meet approximately 65 percent of capital expenditure requirements in 1995. In 1994, the Company issued $36 million of first mortgage bonds, bearing interest rates ranging from 7.05 percent to 8.85 percent. The Company has issued $48 million of long-term debt to date in 1995 at interest rates ranging from 7.79 percent to 8.46 percent, and plans to issue an additional $42 million of long-term debt later in 1995 to meet maturing long-term debt obligations and fund capital expenditures. At December 31, 1994, the Company had $82 million of short-term debt outstanding including $73 million in the form of commercial paper borrowings and $9 million of borrowings from affiliates. As of December 31, 1994, the Company had lines of credit with banks totaling $90 million which are available to provide liquidity support for commercial paper borrowings and other corporate purposes. There were no borrowings under these lines of credit at December 31, 1994. March 20, 1995 MASSACHUSETTS ELECTRIC COMPANY Statements of Income Year Ended December 31, (In Thousands) ------------------------------------ 1994 1993 1992 ---- ---- ---- Operating revenue $1,482,070 $1,468,540 $1,412,948 ---------- ---------- ---------- Operating expenses: Purchased electric energy, principally from New England Power Company, an affiliate 1,074,402 1,081,918 1,065,189 Other operation 215,794 229,438 171,326 Maintenance 35,502 28,168 34,166 Depreciation 42,775 40,848 39,200 Taxes, other than income taxes 28,664 26,527 23,041 Income taxes 22,265 11,055 19,915 ---------- ---------- ---------- Total operating expenses 1,419,402 1,417,954 1,352,837 ---------- ---------- ---------- Operating income 62,668 50,586 60,111 Other income (expense) - net, including related taxes (995) (64) 147 ---------- ---------- ---------- Operating and other income 61,673 50,522 60,258 ---------- ---------- ---------- Interest: Interest on long-term debt 20,967 23,403 21,910 Other interest 6,366 3,638 3,657 Allowance for borrowed funds used during construction - credit (386) (298) (214) ---------- ---------- ---------- Total interest 26,947 26,743 25,353 ---------- ---------- ---------- Net income $ 34,726 $ 23,779 $ 34,905 ========== ========== ========== Statements of Retained Earnings Year Ended December 31, (In Thousands) ------------------------------------ 1994 1993 1992 ---- ---- ---- Retained earnings at beginning of year $ 135,276 $ 134,670 $ 125,976 Net income 34,726 23,779 34,905 Dividends declared on cumulative preferred stock (3,114) (3,772) (3,428) Dividends declared on common stock, $12.50, $7.75, and $9.50 per share, respectively (29,977) (18,585) (22,783) Premium on redemption of preferred stock (816) ---------- ---------- ---------- Retained earnings at end of year $ 136,911 $ 135,276 $ 134,670 ========== ========== ========== The accompanying notes are an integral part of these financial statements. MASSACHUSETTS ELECTRIC COMPANY Balance Sheets At December 31, (In Thousands) ------------------------ 1994 1993 ---- ---- Assets Utility plant, at original cost $1,346,824 $1,279,194 Less accumulated provisions for depreciation 373,501 352,467 ---------- ---------- 973,323 926,727 Construction work in progress 22,672 18,558 ---------- ---------- Net utility plant 995,995 945,285 ---------- ---------- Current assets: Cash 1,225 773 Accounts receivable: From sales of electric energy 137,431 142,532 Other (including $6,609,000 and $3,517,000 from affiliates) 36,022 22,881 Less reserves for doubtful accounts 10,394 10,534 ---------- ---------- 163,059 154,879 Unbilled revenues (Note A-2) 42,800 43,400 Materials and supplies, at average cost 11,524 10,601 Prepaid and other current assets 21,583 19,990 ---------- ---------- Total current assets 240,191 229,643 ---------- ---------- Deferred charges and other assets (Note A-6) 59,536 57,376 ---------- ---------- $1,295,722 $1,232,304 ========== ========== Capitalization and Liabilities Capitalization: Common stock, par value $25 per share, authorized and outstanding 2,398,111 shares $ 59,953 $ 59,953 Premiums on capital stocks 45,862 45,862 Other paid-in capital 141,310 141,310 Retained earnings 136,911 135,276 ---------- ---------- Total common equity 384,036 382,401 Cumulative preferred stock (Note G) 50,000 50,000 Long-term debt 265,631 264,719 ---------- ---------- Total capitalization 699,667 697,120 ---------- ---------- Current liabilities: Long-term debt due in one year 35,000 Short-term debt (including $8,650,000 and $8,350,000 to affiliates) 81,820 37,925 Accounts payable (including $157,076,000 and $160,852,000 to affiliates) 182,102 178,117 Accrued liabilities: Taxes 906 1,133 Interest 7,945 6,784 Other accrued expenses (Note A-7) 27,132 69,823 Customer deposits 4,985 5,907 Dividends payable 13,968 5,575 ---------- ---------- Total current liabilities 353,858 305,264 ---------- ---------- Deferred federal and state income taxes 176,913 146,414 Unamortized investment tax credits 18,816 20,044 Other reserves and deferred credits 46,468 63,462 Commitments and contingencies (Note C) ---------- ---------- $1,295,722 $1,232,304 ========== ========== The accompanying notes are an integral part of these financial statements. MASSACHUSETTS ELECTRIC COMPANY Statements of Cash Flows Year Ended December 31, (In Thousands) ------------------------------------ 1994 1993 1992 ---- ---- ---- Operating activities: Net income $ 34,726 $ 23,779 $ 34,905 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation 42,775 40,848 39,200 Deferred income taxes and investment tax credits - net 28,909 3,126 15,252 Allowance for borrowed funds used during construction (386) (298) (214) Amortization of unbilled revenues (32,300) (2,700) Early retirement program 7,665 Decrease (increase) in accounts receivable, net and unbilled revenues (7,580) (46,434) (20,266) Decrease (increase) in materials and supplies (923) (682) 221 Decrease (increase) in prepaid and other current assets (1,593) 6,229 (24,806) Increase (decrease) in accounts payable 3,985 (9,112) 5,678 Increase (decrease) in other current liabilities (10,379) 32,507 2,804 Other, net (12,982) 14,723 (1,692) -------- -------- -------- Net cash provided by operating activities $ 44,252 $ 69,651 $ 51,082 -------- -------- -------- Investing activities: Plant expenditures, excluding allowance for funds used during construction $(94,105) $(80,473) $(80,547) Other investing activities (4,892) -------- -------- -------- Net cash used in investing activities $(98,997) $(80,473) $(80,547) -------- -------- -------- Financing activities: Capital contributions from parent $ 50,572 $ 10,000 Dividends paid on common stock $(21,584) (19,185) (18,586) Dividends paid on preferred stock (3,114) (3,850) (3,428) Changes in short-term debt 43,895 (7,775) 31,150 Long-term debt - issues 36,000 116,000 150,000 Long-term debt- retirements (117,000) (138,000) Preferred stock - issues 35,000 Preferred stock - retirements (35,000) Premium on reacquisition of long-term debt (7,089) (2,197) Premium on redemption of preferred stock (816) -------- -------- -------- Net cash provided by financing activities $ 55,197 $ 10,857 $ 28,939 -------- -------- -------- Net increase (decrease) in cash and cash equivalents $ 452 $ 35 $ (526) Cash and cash equivalents at beginning of year 773 738 1,264 -------- -------- -------- Cash and cash equivalents at end of year $ 1,225 $ 773 $ 738 ======== ======== ======== Supplementary Information: Interest paid less amounts capitalized $ 24,562 $ 25,220 $ 23,928 -------- -------- -------- Federal and state income taxes paid $ 1,645 $ 12,090 $ 11,521 -------- -------- -------- The accompanying notes are an integral part of these financial statements. MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements Note A - Significant Accounting Policies - ---------------------------------------- 1. System of Accounts: The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by regulatory bodies having jurisdiction. 2. Revenue: Under a 1993 rate agreement, the Company began recognizing, for accounting purposes, revenues for electricity delivered but not yet billed (unbilled revenues). At December 31, 1993, the Company recorded on its balance sheet approximately $43 million of unbilled revenues, of which $11 million was recognized in income in the fourth quarter of 1993 pursuant to this rate agreement, with the balance recognized in 1994. Other accrued revenues are recorded in accordance with rate adjustment mechanisms. 3. Allowance for Funds Used During Construction (AFDC): The Company capitalizes AFDC as part of construction costs. AFDC represents an allowance for the cost of funds used to finance construction. AFDC is capitalized in "Utility plant" with offsetting non-cash credits to "Interest". This method is in accordance with an established rate-making practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFDC rates were 4.8 percent, 3.5 percent, and 3.9 percent, in 1994, 1993, and 1992, respectively. 4. Depreciation: Depreciation is provided annually on a straight-line basis. The provisions for depreciation as a percentage of weighted average depreciable property were 3.3 percent in 1994, 1993, and 1992. 5. Cash: The Company classifies short-term investments with a remaining maturity of 90 days or less as cash. Current banking arrangements do not require outstanding checks to be funded until actually presented for payment. Outstanding checks are therefore recorded in accounts payable until such time as the banks present them for payment. MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements (continued) Note A - Significant Accounting Policies (continued) - ---------------------------------------- 6. Deferred Charges and Other Assets: The components of deferred charges and other assets are as follows: At December 31, (In Thousands) --------------------- 1994 1993 ---- ---- Regulatory assets: Deferred SFAS No. 106 costs (see Note D-2) $16,079 $ 9,663 Environmental response costs (see Note C-2) 9,417 15,002 Unamortized losses on reacquired debt 8,848 9,843 Deferred SFAS No. 109 costs (see Note B) 8,445 8,083 Deferred storm costs 6,545 9,652 Other 1,764 2,212 ------- ------- 51,098 54,455 Other deferred charges and other assets: Non-utility property 5,344 1,697 Other 3,094 1,224 ------- ------- $59,536 $57,376 ======= ======= Electric utility rates are generally based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. These accounting rules require regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the income statement impact of certain costs that are expected to be recovered in future rates. The effects of competition could ultimately cause the operations of the Company, or a portion thereof, to cease meeting the criteria for application of these accounting rules. In such an event, accounting standards applicable to enterprises in general would apply and immediate write-off of any previously deferred costs (regulatory assets) would be necessary in the year in which these criteria were no longer applicable. Approximately $25 million of the regulatory assets at December 31, 1994 listed above are expected to be recovered within 10 years. All of the remainder will be fully recovered within the next 20 years with the exception of the Deferred SFAS No. 109 costs which will take longer to recover. 7. Other Accrued Expenses: The components of other accrued expenses are as follows: At December 31, (In Thousands) --------------------- 1994 1993 ---- ---- Rate adjustment mechanisms $15,087 $21,560 Deferred unbilled revenues 32,300 Accrued wages and benefits 9,969 13,094 Other 2,076 2,869 ------- ------- $27,132 $69,823 ======= ======= MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements (continued) Note B - Income Taxes - --------------------- The Company and other subsidiaries participate with New England Electric System (NEES) in filing consolidated federal income tax returns. The Company's income tax provision is calculated on a separate return basis. Federal income tax returns have been examined and reported on by the Internal Revenue Service through 1991. Total income taxes in the statements of income are as follows: Year Ended December 31, (In Thousands) --------------------------- 1994 1993 1992 ---- ---- ---- Income taxes charged to operations $22,265 $11,055 $19,915 Income taxes charged (credited) to "Other income" (642) 101 143 ------- ------- ------- Total income taxes $21,623 $11,156 $20,058 ======= ======= ======= Total income taxes, as shown above, consist of the following components: Year Ended December 31, (In Thousands) --------------------------- 1994 1993 1992 ---- ---- ---- Current income taxes $(7,286) $ 8,030 $ 4,806 Deferred income taxes 30,137 4,354 16,480 Investment tax credits--net (1,228) (1,228) (1,228) ------- ------- ------- Total income taxes $21,623 $11,156 $20,058 ======= ======= ======= Total income taxes, as shown above, consist of federal and state components as follows: Year Ended December 31, (In Thousands) --------------------------- 1994 1993 1992 ---- ---- ---- Federal income taxes $16,942 $ 7,808 $16,200 State income taxes 4,681 3,348 3,858 ------- ------- ------- Total income taxes $21,623 $11,156 $20,058 ======= ======= ======= Investment tax credits are deferred and amortized over the estimated lives of the property giving rise to the credits. Since the Tax Reform Act of 1986 generally eliminated investment tax credits, the amounts shown above principally reflect the amortization of investment tax credits generated in prior years. Consistent with rate-making policies of the Massachusetts Department of Public Utilities (MDPU), the Company has adopted comprehensive interperiod tax allocation (normalization) for temporary book/tax differences. MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements (continued) Note B - Income Taxes (continued) - --------------------- Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows: Year Ended December 31, (In Thousands) --------------------------- 1994 1993 1992 ---- ---- ---- Computed tax at statutory rate $19,722 $12,227 $18,687 Increases (reductions) in tax resulting from: Amortization of investment tax credits (1,228) (1,228) (1,228) Adjustment of prior year tax accruals (110) (2,528) State income taxes, net of federal income tax benefit 3,043 2,459 2,546 All other differences 196 226 53 ------- ------- ------- Total income taxes $21,623 $11,156 $20,058 ======= ======= ======= The Financial Accounting Standards Board established Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes" which became effective in 1993. The application of this new standard did not have a significant impact on 1993 or 1994 net income. The following table identifies the major components of total deferred income taxes: At December 31, (In Millions) --------------------- 1994 1993 ---- ---- Deferred tax asset: Plant related $ 8 $ 11 Investment tax credits 8 8 All other 45 59 ----- ----- 61 78 ----- ----- Deferred tax liability: Plant related (201) (191) All other (37) (33) ----- ----- (238) (224) ----- ----- Net deferred tax liability $(177) $(146) ===== ===== There were no valuation allowances for deferred tax assets deemed necessary. The deferred taxes resulting from timing differences which appeared on the income statement in 1992 (prior to the adoption of SFAS No. 109 in 1993) primarily included deferred income taxes of $8 million related to utility plant and $8 million in connection with postretirement benefits other than pensions (PBOPs). MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements (continued) Note C - Commitments and Contingencies - -------------------------------------- 1. Plant Expenditures: The Company's utility plant expenditures are estimated to be approximately $105 million in 1995. At December 31, 1994, substantial commitments had been made relative to future planned expenditures. 2. Hazardous Waste: The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. NEES subsidiaries currently have in place an environmental audit program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. The Company has been named as a potentially responsible party (PRP) by either the U.S. Environmental Protection Agency or the Massachusetts Department of Environmental Protection for 17 sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The most prevalent types of hazardous waste sites with which the Company has been associated are manufactured gas locations. The Company is aware of approximately 35 such locations in Massachusetts (including seven of the 17 locations for which the Company is a PRP). The Company is currently aware of other sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. In 1993, the MDPU approved a rate agreement filed by the Company that allows for remediation costs of former manufactured gas sites and certain other hazardous waste sites located in Massachusetts to be met from a non-rate recoverable interest-bearing fund of $30 million established on the Company's books composed of previously recorded reserves of $21 million plus $9 million of additional reserves recorded in the fourth quarter of 1993. Rate recoverable contributions of $3 million, adjusted for inflation, are added to the fund annually in accordance with the agreement. Any shortfalls in the fund would be paid by the Company and be recovered through rates over seven years. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. Where appropriate, the Company intends to seek recovery from its insurers and from other PRPs, but it is uncertain whether and to what extent such efforts would be successful. At December 31, 1994, the Company had total reserves for environmental response costs of $35 million and a related regulatory asset of $9 million. The Company believes that hazardous waste liabilities for all sites of which it is aware, and which are not covered by a rate agreement, will not be material to its financial position. MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements (continued) Note D - Employee Benefits - -------------------------- 1. Pension Plans: Employee Benefits The Company participates with other subsidiaries of NEES in noncontributory defined-benefit plans covering substantially all employees of the Company. The plans provide pension benefits based on the employee's compensation during the five years before retirement. The Company's funding policy is to contribute each year, the net periodic pension cost for that year. However, the contribution for any year will not be less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. Net pension cost for 1994, 1993, and 1992 included the following components: Year Ended December 31, (In Thousands) --------------------------- 1994 1993 1992 ---- ---- ---- Service cost--benefits earned during the period $ 4,134 $ 3,348 $ 3,326 Plus (less): Interest cost on projected benefit obligation 16,435 16,905 15,886 Return on plan assets at expected long-term rate (17,223) (16,683) $(16,441) Amortization 1,060 (208) (260) -------- -------- -------- Net pension cost $ 4,406 $ 3,362 $ 2,511 ======== ======== ======== Assumptions used to determine pension cost: Discount rate 7.25% 8.25% 8.50% Average rate of increase in future compensation levels 4.35% 5.35% 6.70% Expected long-term rate of return on assets 8.75% 8.75% 9.00% -------- -------- -------- Actual return on plan assets $ 1,541 $ 25,785 $ 14,479 ======== ======== ======== Service cost for 1993 does not reflect costs incurred in connection with an early retirement program offered by the Company in that year (see Note D-3). The funded status of the plans cannot be presented separately for the Company as the Company participates in the plans with other NEES subsidiaries. The following table sets forth the funded status of the NEES companies' plans at December 31: MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements (continued) Note D - Employee Benefits (continued) - -------------------------- Retirement Plans, (In Millions) --------------------------- 1994 1993 -------- -------- Union Non-Union Union Non-Union Employee Employee Employee Employee Plans Plans Plans Plans -------- --------- -------- --------- Benefits earned Actuarial present value of accumulated benefit liability: Vested $251 $308 $251 $333 Non-vested 8 9 20 6 ---- ---- ---- ---- Total $259 $317 $271 $339 ==== ==== ==== ==== Reconciliation of funded status Actuarial present value of projected benefit liability $303 $355 $310 $383 Unrecognized prior service costs (8) (4) (8) (6) SFAS No. 87 transition liability not yet recognized (amortized) - (1) - (1) Net loss not yet recognized (amortized) (13) (33) (11) (45) Additional minimum liability recognized - - - 8 ---- ---- ---- ---- 282 317 291 339 ---- ---- ---- ---- Pension fund assets at fair value 293 323 302 318 SFAS No. 87 transition asset not yet recognized (amortized) (13) - (14) - ---- ---- ---- ---- 280 323 288 318 ---- ---- ---- ---- Accrued pension/(prepaid) payments recorded on books $ 2 $ (6) $ 3 $ 21 ==== ==== ==== ==== The assumed discount rate and the assumed average rate of increase in future compensation levels used to calculate pension cost changed effective January 1, 1995 to 8.25 percent and 4.63 percent, respectively. The expected long-term rate of return on assets used to calculate pension cost was not changed from the level shown in the table above. The plans' funded status at December 31, 1994 was calculated using these revised rates. Plan assets are composed primarily of corporate equity, guaranteed investment contracts, debt securities, and cash equivalents. 2. Postretirement Benefit Plans Other Than Pensions and Postemployment Benefits: In 1993, SFAS No. 106, "Employer's Accounting for Postretirement Benefits Other Than Pensions" (PBOPs) went into effect. The Company provides health care and life insurance coverage to eligible retired employees. Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage. MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements (continued) Note D - Employee Benefits (continued) - -------------------------- The total cost of PBOPs for 1994 and 1993 included the following components: Year Ended December 31, (In Thousands) ----------------------- 1994 1993 ---- ---- Service cost--benefits earned during the period $ 2,840 $ 2,613 Plus (less): Interest cost on the accumulated benefit obligation 11,050 12,007 Return on plan assets at expected long-term rate (3,306) (2,095) Amortization 7,287 7,302 ------- ------- Net postretirement benefit cost $17,871 $19,827 ======= ======= Actual return on plan assets $ 265 $ 2,125 ======= ======= The following table sets forth benefits earned and the plans' funded status: At December 31, (In Millions) --------------------- 1994 1993 ---- ---- Accumulated postretirement benefit obligation: Retirees $ 92 $ 100 Fully eligible active plan participants 19 10 Other active plan participants 33 48 ----- ----- Total benefits earned 144 158 Unrecognized transition obligation (131) (138) Net gain (loss) not yet recognized 15 (3) ----- ----- 28 17 Plan assets at fair value 44 35 ----- ----- Prepaid postretirement benefit costs recorded on books $ 16 $ 18 ===== ===== 1995 1994 1993 ---- ---- ---- Assumptions used to determine postretirement benefit cost: Discount rate 8.25% 7.25% 8.25% Expected long-term rate of return on assets 8.50% 8.50% 8.50% Health care cost rate - 1994 and 1993 - 11.00% 12.00% Health care cost rate - 1995 to 2004 8.50% 8.50% 9.50% Health care cost rate - 2005 and beyond 6.25% 6.25% 7.25% MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements (continued) Note D - Employee Benefits (continued) - -------------------------- The plans' funded status at December 31, 1994 and 1993 presented above was calculated using the assumed rates in effect for 1995 and 1994, respectively. The health care cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed rates by 1 percent in each year would increase the accumulated postretirement benefit obligation as of December 31, 1994 by approximately $22 million and the net periodic cost for the year 1994 by approximately $2.5 million. The Company funds the annual tax deductible contributions. Plan assets are invested in equity and debt securities and cash equivalents. Prior to 1993, the Company recorded the cost of PBOPs when paid. These costs amounted to approximately $5.4 million in 1992. The Company has been permitted by the MDPU to phase-in over a four year period that commenced in October 1992, a level of rate recovery that is expected to equal or exceed the amount of PBOP costs calculated in accordance with SFAS No. 106. At December 31, 1994, the Company had deferred for later recovery, $16 million representing that portion of increased PBOP costs not being recovered during this phase-in period. Therefore, adoption of this new accounting standard did not have a significant impact on net income. In the fourth quarter of 1993, the Company recorded a $2 million charge to earnings reflecting the cumulative effect of adopting a new accounting standard for postemployment benefits. 3. 1993 Early Retirement and Special Severance Programs: In February 1993, the Company offered a voluntary early retirement program to non-union employees who were at least 55 years old with 10 years of service. This program was part of an organizational review with the goal of streamlining operations and reducing the work force. The early retirement offer was accepted by 102 employees. A special severance program was also announced in February 1993 for employees affected by the organizational review, but who were not eligible for, or did not accept, the early retirement offer. The Company recorded in the first quarter of 1993 a one-time charge to earnings of approximately $8 million, after tax ($13 million, before tax), to reflect the cost of the early retirement and special severance programs which consisted principally of pension benefits. This total includes the Company's portion of its affiliated service company's cost of these programs. Note E - Short-term Borrowing Arrangements - ------------------------------------------ At December 31, 1994, the Company had $82 million of short-term debt outstanding including $73 million in the form of commercial paper borrowings and $9 million of borrowings from affiliates. At December 31, 1994, the Company had lines of credit with banks totaling $90 million which are available to provide liquidity support for commercial paper borrowings and other corporate purposes. There were no borrowings under these lines of credit at December 31, 1994. Fees are paid in lieu of compensating balances on most lines of credit. The weighted average rate on outstanding short-term borrowings was 6.1 percent at December 31, 1994. MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements (continued) Note F - Intercompany Lending Arrangement - ----------------------------------------- NEES and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies which invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice. Note G - Cumulative Preferred Stock - ----------------------------------- A summary of cumulative preferred stock at December 31, 1994 and 1993 is as follows (in thousands of dollars except for share data): Shares Authorized and Dividends Call Outstanding Amount Declared Price ------------- ------------- ------------- ------ 1994 1993 1994 1993 1994 1993 ---- ---- ---- ---- ---- ---- $25 Par value-- 6.84% Series 600,000 600,000 $15,000 $15,000 $1,026 $ 370 (a) $100 Par value-- 4.44% Series 75,000 75,000 7,500 7,500 333 333 $104.068 4.76% Series 75,000 75,000 7,500 7,500 357 357 103.730 6.99% Series 200,000 200,000 20,000 20,000 1,398 658 (b) 7.80% Series 878 7.84% Series 1,176 ------- ------- ------- ------- ------ ------ Total 950,000 950,000 $50,000 $50,000 $3,114 $3,772 ======= ======= ======= ======= ====== ====== (a) Callable on or after October 1, 1998 at $25.80. (b) Callable on or after August 1, 2003 at $103.50. The annual dividend requirement for total cumulative preferred stock was $3,114,000 for 1994 and 1993. During 1993, all of the Company's 7.80 percent Series and 7.84 percent Series of cumulative preferred stock were redeemed. Total premiums of $816,000 in connection with these redemptions were charged to retained earnings. There are no mandatory redemption provisions on the Company's cumulative preferred stock. MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements (continued) Note H - Long-term Debt - ----------------------- A summary of long-term debt is as follows: At December 31, (In Thousands) ------------------------------ Series Rate % Maturity 1994 1993 - ------ ------ -------- ---- ---- First Mortgage Bonds: R (92-2) 5.875 February 6, 1995 $ 10,000 $ 10,000 S (92-1) 5.860 June 26, 1995 15,000 15,000 S (92-8) 4.730 September 18, 1995 10,000 10,000 R (92-4) 7.230 June 3, 1997 10,000 10,000 R (92-5) 7.210 June 3, 1997 5,000 5,000 S (92-6) 6.120 August 15, 1997 12,000 12,000 S (92-7) 6.010 August 15, 1997 3,000 3,000 R (92-1) 7.240 December 30, 1998 10,000 10,000 S (92-3) 6.630 August 12, 1999 7,500 7,500 S (92-4) 6.600 August 12, 1999 7,500 7,500 S (92-2) 6.980 July 17, 2000 5,000 5,000 S (92-9) 6.310 September 15, 2000 10,000 10,000 R (92-6) 7.710 July 1, 2002 10,000 10,000 S (92-11) 7.250 October 28, 2002 5,000 5,000 S (92-12) 7.340 November 25, 2002 10,000 10,000 T (93-2) 7.090 January 27, 2003 20,000 20,000 T (93-5) 6.400 June 24, 2003 10,000 10,000 U (93-1) 6.240 November 17, 2003 5,000 5,000 U (94-6) 8.520 November 30, 2004 10,000 T (93-7) 6.660 June 23, 2008 5,000 5,000 T (93-8) 6.660 June 30, 2008 5,000 5,000 T (93-10) 6.110 September 8, 2008 10,000 10,000 T (93-11) 6.375 November 17, 2008 10,000 10,000 R (92-3) 8.550 February 7, 2022 5,000 5,000 S (92-5) 8.180 August 1, 2022 10,000 10,000 S (92-10) 8.400 October 26, 2022 5,000 5,000 T (93-1) 8.150 January 20, 2023 10,000 10,000 T (93-3) 7.980 January 27, 2023 10,000 10,000 T (93-4) 7.690 February 24, 2023 10,000 10,000 T (93-6) 7.500 June 23, 2023 3,000 3,000 T (93-9) 7.500 June 29, 2023 7,000 7,000 U (93-2) 7.200 November 15, 2023 10,000 10,000 U (93-3) 7.150 November 24, 2023 1,000 1,000 U (94-1) 7.050 February 2, 2024 10,000 U (94-2) 8.080 May 2, 2024 5,000 U (94-3) 8.030 June 14, 2024 5,000 U (94-4) 8.160 August 9, 2024 5,000 U (94-5) 8.850 November 7, 2024 1,000 Unamortized discounts and premiums (1,369) (1,281) -------- -------- Total long-term debt 300,631 264,719 ======== ======== Long-term debt due within year (35,000) -------- -------- $265,631 $264,719 ======== ======== MASSACHUSETTS ELECTRIC COMPANY Notes to Financial Statements (continued) Note H - Long-term Debt (continued) - ----------------------- Substantially all of the properties and franchises of the Company are subject to the lien of mortgage indentures under which the first mortgage bonds have been issued. The Company will make cash payments of $35,000,000 in 1995, $30,000,000 in 1997, $10,000,000 in 1998, and $15,000,000 in 1999 to retire maturing mortgage bonds. There are no cash payments required in 1996. Note I - Fair Value of Financial Instruments - -------------------------------------------- At December 31, 1994, the Company's long-term debt, including long-term debt due within one year, had a carrying value of approximately $301,000,000 and had a fair value of approximately $280,000,000. The fair market value of the Company's long-term debt was estimated based on the quoted prices for similar issues or on the current rates offered to the Company for debt of the same remaining maturity. The fair value of the Company's short-term debt equals carrying value. Note J - Restrictions on Retained Earning Available for Dividends on Common Stock - ------------------------------------------------------- As long as any preferred stock is outstanding, certain restrictions on payment of dividends on common stock would come into effect if the "junior stock equity" was, or by reason of payment of such dividends became, less than 25 percent of "total capitalization". However, the junior stock equity at December 31, 1994 was 52 percent of total capitalization, including long-term debt due in one year, and, accordingly, none of the Company's retained earnings at December 31, 1994 were restricted as to dividends on common stock under the foregoing restrictions. Under restrictions contained in the indentures relating to first mortgage bonds, $30,113,000 of the Company's retained earnings at December 31, 1994 were restricted as to dividends on common stock. Note K - Supplementary Income Statement Information - --------------------------------------------------- Advertising expenses, expenditures for research and development, and rents were not material and there were no royalties paid. Taxes, other than income taxes, charged to operating expenses are set forth by classes as follows: Year Ended December 31, (In Thousands) --------------------------- 1994 1993 1992 ---- ---- ---- Municipal property taxes $21,186 $19,620 $16,525 Federal and state payroll and other taxes 7,478 6,907 6,516 ------- ------- ------- $28,664 $26,527 $23,041 ======= ======= ======= New England Power Service Company, an affiliated service company operating pursuant to the provisions of Section 13 of the Public Utility Holding Company Act of 1935, furnished services to the Company at the cost of such services. These costs amounted to $71,107,000, $61,515,000, and $47,360,000, including capitalized construction costs of $8,977,000, $9,038,000, and $8,306,000, for each of the years 1994, 1993, and 1992, respectively. MASSACHUSETTS ELECTRIC COMPANY Operating Statistics (Unaudited)
Year Ended December 31, ----------------------- 1994 1993 1992 1991 1990 ---- ---- ---- ---- ---- Sources of Energy (Thousands of KWH) Purchased energy: From New England Power Company, an affiliate 16,455,774 16,179,204 16,005,087 15,971,746 16,206,581 From others 3,364 12,676 13,916 12,865 13,180 ---------- ---------- ---------- ---------- ---------- Total purchased 16,459,138 16,191,880 16,019,003 15,984,611 16,219,761 Losses, company use, etc. (733,804) (740,390) (711,157) (730,694) (699,383) ---------- ---------- ---------- ---------- ---------- Total sources of energy 15,725,334 15,451,490 15,307,846 15,253,917 15,520,378 ========== ========== ========== ========== ========== Sales of Energy (Thousands of KWH) Residential 5,798,806 5,694,539 5,645,350 5,568,452 5,629,825 Commercial 5,936,170 5,743,924 5,645,867 5,585,604 5,648,759 Industrial 3,885,391 3,850,075 3,907,040 3,979,418 4,113,647 Other 95,382 99,991 105,842 113,444 120,142 ---------- ---------- ---------- ---------- ---------- Total sales to ultimate customers 15,715,749 15,388,529 15,304,099 15,246,918 15,512,373 Sales for resale 9,585 62,961 3,747 6,999 8,005 ---------- ---------- ---------- ---------- ---------- Total sales of energy 15,725,334 15,451,490 15,307,846 15,253,917 15,520,378 ========== ========== ========== ========== ========== Maximum Demand (Kw - one hour peak) 3,016,000 2,819,000 2,791,000 2,888,000 2,761,000 Average Annual Use per Residential Customer (KWH) 6,948 6,888 6,886 6,832 6,926 Number of Customers at December 31 Residential 839,443 831,223 824,072 817,270 814,558 Commercial 95,430 93,414 92,281 81,355 85,597 Industrial 4,551 4,637 4,624 4,650 4,667 Other 880 906 952 986 910 ---------- ---------- ---------- ---------- ---------- Total ultimate customers 940,304 930,180 921,929 904,261 905,732 Other (for resale) 178 278 22 21 22 ---------- ---------- ---------- ---------- ---------- Total customers 940,482 930,458 921,951 904,282 905,754 ========== ========== ========== ========== ==========
NEW ENGLAND POWER COMPANY Operating Statistics (Unaudited) (continued)
Year Ended December 31, ----------------------- 1994 1993 1992 1991 1990 ---- ---- ---- ---- ---- Operating Revenue (In Thousands) Residential $ 589,447 $ 590,106 $ 549,884 $ 521,140 $ 475,004 Commercial 523,806 515,874 510,638 490,078 442,478 Industrial 301,144 314,132 319,905 318,502 294,037 Other 17,185 17,343 17,489 18,304 17,873 ---------- ---------- ---------- ---------- ---------- Total revenue from ultimate customers 1,431,582 1,437,455 1,397,916 1,348,024 1,229,392 Unbilled revenues 31,700 11,100 Sales for resale 935 5,401 278 518 517 ---------- ---------- ---------- ---------- ---------- Total revenue from electric sales 1,464,217 1,453,956 1,398,194 1,348,542 1,229,909 Other operating revenue 17,853 14,584 14,754 15,346 13,036 ---------- ---------- ---------- ---------- ---------- Total operating revenue $1,482,070 $1,468,540 $1,412,948 $1,363,888 $1,242,945 ========== ========== ========== ========== ==========
MASSACHUSETTS ELECTRIC COMPANY Selected Financial Information Year Ended December 31, (In Millions) ------------------------------------- 1994 1993 1992 1991 1990 ---- ---- ---- ---- ---- Operating revenue: Electric sales (excluding fuel cost recovery) $1,088 $1,062 $1,012 $ 984 $ 898 Fuel cost recovery 376 392 386 366 332 Other 18 15 15 15 13 ------ ------ ------ ------ ------ Total operating revenue $1,482 $1,469 $1,413 $1,364 $1,243 Net income $ 35 $ 24 $ 35 $ 25 $ 35 Total assets $1,296 $1,232 $1,015 $1,017 $1,014 Capitalization: Common equity $ 384 $ 382 $ 331 $ 313 $ 296 Cumulative preferred stock 50 50 50 50 50 Long-term debt 266 265 266 194 254 ------ ------ ------ ------ ------ Total capitalization $ 700 $ 697 $ 647 $ 557 $ 600 Preferred dividends declared $ 3 $ 4 $ 3 $ 3 $ 3 Common dividends declared $ 30 $ 19 $ 23 $ 5 $ 16 Selected Quarterly Financial Information (Unaudited) First Second Third Fourth (In Thousands) Quarter Quarter Quarter Quarter* - -------------- ------- ------- ------- -------- 1994 Operating revenue $381,712 $339,886 $376,582 $383,890 Operating income $ 17,124 $ 15,054 $ 10,120 $ 20,370 Net income $ 9,572 $ 8,215 $ 1,431 $ 15,508 1993 Operating revenue $378,441 $340,293 $376,137 $373,669 Operating income $ 13,831 $ 2,573 $ 7,988 $ 26,194 Net income (loss) $ 6,060 $ (4,144) $ 2,204 $ 19,659 Per share data is not relevant because the Company's common stock is wholly-owned by New England Electric System. * See Note A-2 for discussion of significant item that affected fourth quarter 1993 net income. A copy of Massachusetts Electric Company's Annual Report on Form 10-K to the Securities and Exchange Commission, for the year ended December 31, 1994, will be available on or about April 1, 1995, without charge, upon written request to Massachusetts Electric Company, Shareholder Services Department, 25 Research Drive, Westborough, Massachusetts 01582. EX-24 18 EXHIBIT 24 POWER OF ATTORNEY Each of the undersigned directors of Massachusetts Electric Company (the "Company"), individually as a director of the Company, hereby constitutes and appoints John G. Cochrane, Thomas F. Killeen, and Geraldine M. Zipser, individually, as attorney-in-fact to execute on behalf of the undersigned the Company's annual report on Form 10-K for the year ended December 31, 1994, to be filed with the Securities and Exchange Commission, and to execute any appropriate amendment or amendments thereto as may be required by law. Dated this 15th day of March, 1995. s/ Urville J. Beaumont s/ John F. Reilly Urville J. Beaumont John F. Reilly s/ Joan T. Bok s/ John W. Rowe Joan T. Bok John W. Rowe s/ Sally L. Collins s/ Richard P. Sergel Sally L. Collins Richard P. Sergel s/ John H. Dickson s/ Richard M. Shribman John H. Dickson Richard M. Shribman s/ Roslyn M. Watson Charles B. Housen Roslyn M. Watson s/ Patricia McGovern Patricia McGovern EX-27 19 EXHIBIT 27 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT 1,000 DEC-31-1994 DEC-31-1993 DEC-31-1994 DEC-31-1993 12-MOS 12-MOS PER-BOOK PER-BOOK 995,995 945,285 0 0 240,191 229,643 59,536 57,376 0 0 1,295,722 1,232,304 59,953 59,953 187,172 187,172 136,911 135,276 384,036 382,401 0 0 50,000 50,000 265,631 264,719 81,820 37,925 0 0 0 0 35,000 0 0 0 0 0 0 0 479,235 497,259 1,295,722 1,232,304 1,482,070 1,468,540 22,265 11,055 1,397,137 1,406,899 1,419,402 1,417,954 62,668 50,586 (995) (64) 61,673 50,522 26,947 26,743 34,726 23,779 3,114 3,772 31,612 19,191 29,977 18,585 20,967 23,403 44,252 69,651 0 0 0 0 Total deferred charges includes other assets. Short-term notes includes commercial paper obligations and short-term debt to affiliates. EX-13 20 EXHIBIT 13 Annual Report 1994 The Narragansett Electric Company A Subsidiary of New England Electric System (Logo) Narragansett Electric A New England Electric System company The Narragansett Electric Company 280 Melrose Street Providence, Rhode Island 02901 Directors (As of December 31, 1994) Joan T. Bok John W. Rowe Chairman of the Board of New England President and Chief Executive Electric System Officer of New England Electric System Stephen A. Cardi Treasurer, Cardi Corporation Richard P. Sergel (Construction), Warwick, Rhode Island Chairman of the Company and Vice President of New England Electric Frances H. Gammell System Treasurer and Secretary, Original Bradford Soap Works, Inc., West Warwick, William E. Trueheart Rhode Island President of Bryant College, Smithfield, Rhode Island Joseph J. Kirby President, Washington Trust Bancorp, John A. Wilson, Jr. Inc., Westerly, Rhode Island Consultant to and former President of Wanskuck Company (Cable reel Robert L. McCabe manufacturer), Providence, Rhode President and Chief Executive Officer Island and Consultant to Hinkley, of the Company Allen, Tobin and Silverstein Officers (As of December 31, 1994) Richard P. Sergel James V. Mahoney Chairman of the Company and Vice Vice President President of New England Electric System Richard Nadeau Vice President Robert L. McCabe President and Chief Executive Officer Michael F. Ryan Vice President William Watkins, Jr. Executive Vice President Thomas G. Robinson Secretary Francis X. Beirne Vice President John G. Cochrane Assistant Treasurer of the Company Richard W. Frost and of an affiliate Vice President David J. Saggau Alfred D. Houston Assistant Secretary Vice President and Treasurer of the Company and Executive Vice President Howard W. McDowell and Chief Financial Officer of New Controller of the Company and of England Electric System certain affiliates Transfer Agent, Dividend Paying Agent, and Registrar of Preferred Stock Fleet National Bank, Providence, Rhode Island This report is not to be considered an offer to sell or buy or solicitation of an offer to sell or buy any security. The Narragansett Electric Company The Narragansett Electric Company is a wholly-owned subsidiary of New England Electric System (NEES) operating in Rhode Island. The Company's business is the distribution and sale of electricity at retail. Electric service is provided to approximately 324,000 customers in 27 cities and towns having a population of approximately 725,000 (1990 Census). The Company's service area, which includes urban, suburban, and rural areas, covers about 839 square miles or 80 percent of Rhode Island, and includes the cities of Providence, East Providence, Cranston, and Warwick. The diversified economy produces fabricated metal products, electrical and industrial machinery, transportation equipment, textiles, jewelry, silverware, and chemical products. In addition, a broad range of professional, banking, medical, and educational institutions is served. The properties of the Company include an integrated system of transmission and distribution lines and substations. In addition, the Company owns a 10 percent share of a steam-electric generating station which is in the process of being repowered. The repowering will more than triple the power generating capacity of the station to 489 megawatts. The entire output of this plant is made available to New England Power Company (NEP), an affiliate, as part of the integrated NEES system. Under a contract with NEP, the Company purchases its electric energy requirements from NEP. The contract provides for the integration of the Company's generating and transmission facilities with NEP's facilities in order to achieve maximum economy and reliability. The contract also provides for the application of credits against the Company's power bills from NEP for costs associated with the Company's facilities so integrated. The Company and NEP are members of the New England Power Pool, which provides for the coordination of the planning and operation of the generation and transmission facilities in New England, and the region-wide central dispatch of generation. Report of Independent Accountants The Narragansett Electric Company, Providence, Rhode Island: We have audited the accompanying balance sheets of The Narragansett Electric Company (the Company), a wholly-owned subsidiary of New England Electric System, as of December 31, 1994 and 1993 and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. Boston, Massachusetts COOPERS & LYBRAND L.L.P. February 27, 1995 The Narragansett Electric Company Financial Review Overview Net income for 1994 increased by $300,000 compared with 1993. The increase was primarily due to the inclusion in 1993 of a one-time charge associated with an early retirement program. The increase also reflects kilowatthour (KWH) sales growth in 1994, the commencement of recognition of revenues for electricity delivered but not yet billed (unbilled revenues) pursuant to a 1994 rate agreement, and increased allowance for funds used during construction. These increases were largely offset by rate discounts to large commercial and industrial customers also implemented as part of this rate agreement, increases in other operation expenses, and increased interest expense due to additional debt outstanding. Net income decreased by $7 million in 1993. This decrease was primarily due to increased operation and maintenance expenses as well as a reduction in incentives recorded on the Company's demand-side management (DSM) programs. This increase in operation and maintenance expense included the effects of an early retirement program discussed above. The decrease in income was partially offset by an increase in KWH sales to ultimate customers. Rate Activity On March 1, 1995, the Company filed with the Rhode Island Public Utilities Commission (RIPUC) a request to increase its base rates by $30.5 million to be effective December 1995. As an alterative to the December 1995 effective date, the Company proposed to phase its requested rate increase in two steps--the first step in June 1995 ($13 million) and the second step in June 1996. As part of its filing, the Company proposed a special rate discount of 8 percent of base rates, for manufacturing customers that agree to give the Company a five-year notice before they purchase power from another supplier or generate any additional power themselves. In July 1994, the RIPUC approved a rate agreement between the Company and the Rhode Island Division of Public Utilities and Carriers that provides for a 5 percent base rate discount, excluding fuel costs, for the Company's large commercial and industrial customers who sign an agreement to give a five-year notice to the Company before they purchase power from another supplier or generate any additional power themselves. The notice provision may be reduced from five to three years under certain conditions. The aggregate amount of the Company's discounts was $1.5 million in 1994 and is expected to be approximately $3 million per year thereafter. Customers representing over 64 percent of revenues from large commercial and industrial customers have signed these agreements. In addition, commencing in 1995 the cost of these discounts is being passed on to New England Power Company (NEP), the Company's affiliated wholesale power supplier. This is the result of a NEP rate settlement that was approved by the Federal Energy Regulatory Commission (FERC) in early 1995. The agreement also provides for the Company to recognize, for accounting purposes, $14 million of unbilled revenues over a 21 month period beginning April 1994 through December 1995. Effective March 1993, the RIPUC approved a new purchased power cost adjustment (PPCA) mechanism for the recovery of all of the Company's purchased power costs, excluding fuel charges which continue to be Rate Activity (continued) recovered through a separate adjustment mechanism. Under the new mechanism any over or under-collections of purchased power expense will ultimately be passed on to customers including the effects of peak-demand billing fluctuations. The Company accrues the effects of this new mechanism on its books on a current basis. In August 1994, the RIPUC gave notice that it intends to open a proceeding to consider the effect of fuel adjustment clauses on utility incentives to reduce costs. Effective January 1993, the RIPUC approved a $1.5 million increase in rates for the Company, representing the first step of a three year phase-in of the Company's recovery of costs associated with postretirement benefits other than pensions (PBOPs). The second and third $1.5 million increases took effect in January 1994 and 1995, respectively. A 1986 Rhode Island Supreme Court decision held that the RIPUC's rate-making power includes the authority to order refunds of amounts earned in excess of an allowed return. As a result, the RIPUC monitors the Company's earnings on a regular basis. Demand-Side Management The Company regularly files its demand-side management (DSM) programs with the RIPUC and has received approval to recover DSM program expenditures in rates on a current basis. These expenditures were $10 million, $12 million, and $12 million in 1994, 1993, and 1992, respectively. Since 1990, the Company has been allowed to earn incentives based on the results of its DSM programs. The Company must be able to demonstrate the electricity savings produced by its DSM programs to the RIPUC before incentives are recorded. The Company recorded before-tax incentives of $0.6 million, $0.5 million, and $1.3 million in 1994, 1993, and 1992, respectively. The Company has received regulatory orders that will give it the opportunity to continue to earn incentives based on 1995 DSM program results. Operating Revenue The following table summarizes the changes in operating revenue: Increase (Decrease) in Operating Revenue - ----------------------------------------------------------------------- (In Millions) 1994 1993 - ----------------------------------------------------------------------- Sales growth $ 5 $ 6 General rate changes - 2 Unbilled revenues 5 - PPCA mechanism (2) 2 DSM recovery (2) - Fuel recovery (7) 5 --------------------- $(1) $15 ===================== KWH sales billed to ultimate customers in 1994 increased by 0.6 percent over 1993. The increase in KWH sales reflects an improved economy partially offset by a loss of sales attributable to the May 1994 plant closing of one Operating Revenue (continued) of the Company's largest customers. Revenues from this customer, excluding fuel and purchased power costs, were approximately $1.4 million on an annual basis. KWH sales in 1993 increased 2.9 percent over 1992 sales, reflecting more normal weather conditions in 1993 compared with 1992, partially offset by the fact that 1992 included an extra day for leap year. The Company's rates contain a fuel clause and a PPCA provision. These mechanisms are designed to allow the Company to pass on to its customers changes in purchased energy costs resulting from rate increases or decreases by NEP, the Company's affiliated wholesale power supplier. In the third quarter of 1994, the Company began recognizing unbilled revenues according to its rate agreement filed in July 1994 with the RIPUC. For a further discussion of unbilled revenues, see "Rate Activity" section. Operating Expenses The following table summarizes the changes in total operating expenses discussed below: Increase (Decrease) in Operating Expenses - ------------------------------------------------------------------------- (In Millions) 1994 1993 - ------------------------------------------------------------------------- Fuel for generation $ - $(3) Purchased electric energy: Fuel costs (7) 5 NEP refunds 1 2 Purchases and demand charges from NEP 2 4 Integrated facilities credit from NEP (6) 13 Other operation and maintenance: DSM (2) - Thermal generation - (6) Other 1 13 Depreciation 7 (2) Taxes 1 (4) --------------- $(3) $22 =============== The entire output of the Company's generating capacity is made available to NEP. The Company receives a credit on its purchased power bill from NEP for its fuel costs and other generation and transmission costs. The change in the integrated facilities credit from NEP for 1994 shown in the above table reflects increased credits for dismantlement costs being incurred on the Company's previously retired South Street generating station. These increased costs for dismantlement are reflected in the increase in depreciation shown above. The change in the integrated facilities credit from NEP for 1993 reflects decreased credits is attributable to the Company's mid-1992 sale of 90 percent of the Manchester Street Station to NEP as part of the Manchester Street repowering project. The decreases in fuel for generation and thermal generation-related operation and maintenance costs in 1993 are also due to this sale (see "Repowering of Manchester Street Station" section). Operating Expenses (continued) The changes in the fuel cost component of purchased power in 1994 and 1993 reflect changes in the amount of New England Energy Incorporated's (NEEI) costs passed through by NEP. NEEI is an affiliated company involved in oil and gas exploration and development. The 1994 decrease also reflects a reduction in the fuel component of NEP's purchased electric energy costs. In addition, the increase in fuel costs in 1993 reflects increased KWH purchases. The change in other operation and maintenance expense in both 1993 and 1994 reflects the one-time charge of $5 million in 1993 associated with an early retirement program. The increase in both periods also reflects increased computer system development costs and postretirement benefit costs as well as general increases in other areas. Allowance for Funds Used During Construction (AFDC) AFDC increased in 1994 and 1993 due to increased construction work in progress associated with the repowering of the Manchester Street Station (see "Repowering of Manchester Street Station" section). Hazardous Waste The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. New England Electric System (NEES) subsidiaries currently have in place an environmental audit program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. The Company has been named as a potentially responsible party (PRP) by either the U.S. Environmental Protection Agency or the Massachusetts Department of Environmental Protection for two sites (one of which is located in Massachusetts) at which hazardous waste is alleged to have been disposed. The Company is currently aware of other sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. Gas was manufactured from coal in Rhode Island in the past. The Company is aware of five sites on which gas was manufactured or manufactured gas was stored that were owned either by the Company or by its predecessor companies. It is not known to what extent the Company would be held liable for hazardous wastes, if any, left at these manufactured gas locations. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. A preliminary review by a consultant hired by the NEES companies of the potential cost of investigating and, if necessary, remediating Rhode Island manufactured gas sites resulted in costs per site Hazardous Waste (continued) ranging from less than $1 million to $8 million. An informal survey of other utilities conducted on behalf of NEES and its subsidiaries indicated costs in a similar range. Where appropriate, the Company intends to seek recovery from its insurers and from other PRPs, but it is uncertain whether and to what extent such efforts would be successful. The Company believes that hazardous waste liabilities for all sites of which it is aware will not be material to its financial position. Electric and Magnetic Fields (EMF) In recent years, concerns have been raised about whether EMF, which occur near transmission and distribution lines as well as near household wiring and appliances, cause or contribute to adverse health effects. Numerous studies on the effects of these fields, some of them sponsored by electric utilities (including NEES companies), have been conducted and are continuing. Some of the studies have suggested associations between certain EMF and health effects, including various types of cancer, while other studies have not substantiated such associations. It is impossible to predict the ultimate impact on the Company and the electric utility industry if further investigations were to demonstrate that the present electricity delivery system is contributing to increased risk of cancer or other health problems. Many utilities, including the NEES companies, have been contacted by customers regarding a potential relationship between EMF and adverse health effects. To date, no court in the United States has ruled that EMF from electrical facilities cause adverse health effects and no utility has been found liable for personal injuries alleged to have been caused by EMF. In any event, the Company believes that it currently has adequate insurance coverage for personal injury claims. Several state courts have recognized a cause of action for damage to property values in transmission line condemnation cases based on the fear that power lines cause cancer. It is difficult to predict what the impact on the Company would be if this cause of action is recognized in Rhode Island and in contexts other than condemnation cases. Bills have been introduced unsuccessfully in the past in the Rhode Island legislature to require that transmission lines be placed underground. Competitive Conditions The electric utility business is being subjected to increasing competitive pressures, stemming from a combination of trends, including increasing electric rates, improved technologies, and new regulations and legislation intended to foster competition. To date, this competition has been most prominent in the bulk power market in which non-utility generating sources have noticeably increased their market share. For example, since non-utilities were allowed to enter the wholesale generation market, two-thirds of NEP's new generating capability has come from independent generating sources and Hydro-Quebec. Competitive Conditions (continued) Electric utilities are also facing increased competition in the retail market. Currently, retail competition includes competition with alternative fuel suppliers (including natural gas companies) for heating and cooling, competition with customer-owned generation to displace purchases from electric utilities, and direct competition among electric utilities to attract major new facilities to their service territories. Electric utilities, including the Company, are under increasing pressure from large commercial and industrial customers to discount rates or face the possibility that such customers might relocate or seek alternate suppliers. Across the country, including Rhode Island and the other states in which the Company's affiliates operate, there have been an increasing number of proposals to allow retail customers to choose their electricity supplier, with utilities required to deliver that electricity over their transmission and distribution systems. In Rhode Island, the RIPUC has convened a task force of utilities, commercial and industrial customers, regulators, and other interested parties to prepare a report by May 1995 regarding restructuring the industry. The Massachusetts Division of Energy Resources (DOER) proposed in January 1995 that the Massachusetts Department of Public Utilities (MDPU) modify its regulations to allow retail utility customers to choose a supplier and bid for access to the local utility's transmission and distribution systems in situations where new generating capacity is needed. The NEES companies have indicated their support for the DOER proposal. The Company's Massachusetts retail affiliate has announced plans to propose a limited bidding experiment consistent with the DOER proposal. Also in Massachusetts, the MDPU initiated a proceeding in February 1995 regarding electric industry regulation and structure. In New Hampshire, the New Hampshire Public Utilities Commission is considering the proposal of a new company to sell electricity at retail to large customers in New Hampshire. The impact of increased customer choice on the financial condition of utilities is uncertain. In recent years, substantial surplus generating capacity in the Northeast has resulted in the sale of bulk power by utilities to other utilities at prices substantially below the total costs of owning and operating, or contracting for, such generating capacity. Should retail customers gain access to the bulk power market, particularly while surplus capacity exists, it is unlikely that utilities would be able to charge power prices which fully cover their costs. Such unrecovered costs, which could be substantial, have been referred to by the industry as stranded costs. Whether and to what extent utilities should be able to recover stranded costs resulting from increased customer choice has been the subject of much debate. In 1994, the FERC issued a notice of proposed rule-making on the recovery of stranded costs. The NEES companies and other utilities have taken the position that when a regulatory body changes policies which govern customer choice and the resultant rates paid by customers, utilities must be compensated for commitments made under the former policies. Furthermore, the utility industry believes that recovery of stranded costs is necessary to promote efficient competition among market participants. Previously, the FERC ruled in 1992, in a proceeding not involving NEES subsidiaries, that a utility may recover such stranded costs from a departing wholesale requirements customer. On appeal, the United States Court of Appeals for the District of Columbia Circuit has questioned whether allowing utilities to recover stranded costs is anti-competitive and the Court remanded the case back to the FERC for further proceedings and development of the competitive issues. Competitive Conditions (continued) In addition to the arguments described above, the NEES companies have taken the position that, because utility transmission and distribution assets have a replacement value in excess of their historic costs (on which utility rates are set), utilities should have the ability to recover stranded generation-related costs by realizing the higher value of transmission and distribution assets. The NEES companies have stated their willingness, in order to assure stranded cost recovery and promote increased competition, to consider divesting their transmission system, either through sale or spinoff. The NEES companies are actively responding to current and anticipated competitive pressures in a variety of ways, including cost control and a 1993 corporate reorganization into separate retail and wholesale business units. The retail business unit, which includes the Company, is responding to competition through the development of an EnergyFIT program, which offers comprehensive value-added services for large business customers, intensified business development efforts, including economic development rates and service packages to encourage businesses to locate in the Company's service territory, and development of new pricing and service options for customers. Additionally, more than 75 percent of the Company's large commercial and industrial customers (representing 64 percent of eligible revenues) have signed service extension discount contracts providing for discounts in exchange for agreements requiring three to five years notice before they may change electricity suppliers (see "Rate Activity" section). As part of their long-term planning process, the NEES companies are from time to time evaluating other strategies, such as business combinations and other forms of restructuring, to better respond to the changing competitive environment. Since the largest component of the Company's costs is represented by the cost of power purchased from NEP, its competitive position is affected by NEP's ability to control costs. NEP is controlling costs and positioning itself for increased competition by freezing base rates until at least 1997 (wholesale base rates were last raised in March 1992), terminating certain purchased power and gas pipeline contracts, shutting down uneconomic generating stations, and accelerating the recovery of uneconomic assets and other deferred costs. In addition, NEP's wholesale tariff requires its wholesale customers, including the Company and NEES's other retail subsidiaries, to provide seven years notice before they may terminate the tariff. Electric utility rates are generally based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. These accounting rules require regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the income statement impact of certain costs that are expected to be recovered in future rates. The effects of competition could ultimately cause the operations of the Company, or a portion thereof, to cease meeting the criteria for application of these accounting rules. In such an event, accounting standards applicable to enterprises in general would apply and immediate write-off of any previously deferred costs (regulatory assets) would be necessary in the year in which these criteria were no longer applicable. In addition, if, because of competition, utilities are unable to recover all of their costs in rates, it may be necessary to write off those costs that are not recoverable. Utility Plant Expenditures and Financings Cash expenditures for utility plant totaled $93 million in 1994, including $33 million related to the Manchester Street Station repowering project discussed below. The funds necessary for utility plant expenditures were primarily provided by net cash from operating activities, after the payment of dividends, the issuance of long-term and short-term debt, and a capital contribution from NEES. Cash expenditures for utility plant for 1995 are estimated to be $55 million (including approximately $16 million related to the repowering of Manchester Street Station). Internally generated funds are estimated to provide 50 percent of these needs in 1995. Cash expenditures for utility plant are also expected to be funded through the issuance of long-term and short-term debt. In 1994, the Company issued $33 million of first mortgage bonds bearing interest rates ranging from 6.91 percent to 8.33 percent. The Company has issued $5 million of long-term debt to date in 1995 at an interest rate of 7.81 percent and plans to issue an additional $20 million of long-term debt later in 1995 to reduce short-term debt and fund capital expenditures. At December 31, 1994, the Company had $30 million of short-term debt outstanding in the form of commercial paper borrowings. As of December 31, 1994, the Company had lines of credit with banks totaling $41 million. There were no borrowings under these lines of credit at December 31, 1994. Repowering of Manchester Street Station The Company's major construction project is the repowering of Manchester Street Station, a 140 megawatt electric generating station in Providence, Rhode Island. Repowering will more than triple the power generation capacity of Manchester Street Station and substantially increase the plant's thermal efficiency. To facilitate financing this project, the Company sold a 90 percent interest in the existing station to NEP effective July 1, 1992. The total cost for the generating station, scheduled to be placed in service in late 1995, is estimated to be approximately $520 million including AFDC. At December 31, 1994, $298 million, including AFDC, had been spent on the generating station (including $28 million by the Company). In addition, related transmission improvements were placed in service in September 1994 at a cost of approximately $60 million (including approximately $45 million by the Company). The Narragansett Electric Company Statements of Income
- ----------------------------------------------------------------------------------------- Year Ended December 31, (In Thousands) 1994 1993 1992 - ----------------------------------------------------------------------------------------- Operating revenue $481,669 $483,028 $468,252 Operating expenses: Purchased electric energy, principally from New England Power Company, an affiliate 300,678 310,895 286,483 Other operation 73,082 73,723 69,602 Maintenance 12,281 12,179 12,286 Depreciation 24,813 17,645 19,826 Taxes, other than federal income taxes 35,818 35,846 35,172 Federal income taxes 4,883 4,175 8,984 ---------------------------------- Total operating expenses 451,555 454,463 432,353 ---------------------------------- Operating income 30,114 28,565 35,899 Other income: Allowance for equity funds used during construction 1,028 543 10 Other income (expense) - net, including related taxes (856) (634) (639) ---------------------------------- Operating and other income 30,286 28,474 35,270 ---------------------------------- Interest: Interest on long-term debt 14,334 12,715 13,290 Other interest 2,897 2,074 1,277 Allowance for borrowed funds used during construction - credit (1,534) (589) (349) ---------------------------------- Total interest 15,697 14,200 14,218 ---------------------------------- Net income $ 14,589 $ 14,274 $ 21,052 ================================== Statements of Retained Earnings - ----------------------------------------------------------------------------------------- Year Ended December 31, (In Thousands) 1994 1993 1992 - ----------------------------------------------------------------------------------------- Retained earnings at beginning of year $81,659 $74,207 $59,804 Net income 14,589 14,274 21,052 Dividends declared on cumulative preferred stock (2,143) (1,931) (1,553) Dividends declared on common stock, $2.25, $4.00, and $4.50 per share, respectively (2,549) (4,530) (5,096) Premium on redemption of preferred stock (361) ---------------------------------- Retained earnings at end of year $91,556 $81,659 $74,207 ================================== The accompanying notes are an integral part of these financial statements.
The Narragansett Electric Company Balance Sheets
- ----------------------------------------------------------------------------------------- At December 31, (In Thousands) 1994 1993 - ----------------------------------------------------------------------------------------- Assets Utility plant, at original cost $617,498 $534,569 Less accumulated provisions for depreciation 161,557 156,652 --------------------- 455,941 377,917 Construction work in progress 35,974 43,660 --------------------- Net utility plant 491,915 421,577 --------------------- Current assets: Cash 713 838 Accounts receivable: From sales of electric energy 51,278 55,795 Other (including $9,306,000 and $1,087,000 from affiliates) 17,953 11,701 Less reserves for doubtful accounts 4,472 3,800 --------------------- 64,759 63,696 Unbilled revenues (Note A-2) 13,100 Fuel, materials, and supplies, at average cost 5,170 4,572 Prepaid and other current assets 13,993 11,515 --------------------- Total current assets 97,735 80,621 --------------------- Deferred charges and other assets (Note A-6) 57,727 53,709 --------------------- $647,377 $555,907 ===================== Capitalization and Liabilities Capitalization: Common stock, par value $50 per share, authorized and outstanding 1,132,487 shares $ 56,624 $ 56,624 Premiums on preferred stocks 170 170 Other paid-in capital 60,000 45,000 Retained earnings 91,556 81,659 --------------------- Total common equity 208,350 183,453 Cumulative preferred stock, par value $50 per share 36,500 36,500 Long-term debt 188,862 155,972 --------------------- Total capitalization 433,712 375,925 --------------------- Current liabilities: Short-term debt (including $19,725,000 to affiliates in 1993) 29,800 19,725 Accounts payable (including $47,900,000 and $43,468,000 to affiliates) 56,139 51,005 Accrued liabilities: Taxes 143 1,712 Interest 5,615 4,921 Other accrued expenses (Note A-2) 25,346 11,798 Customer deposits 5,261 5,622 Dividends payable 819 1,102 --------------------- Total current liabilities 123,123 95,885 --------------------- Deferred federal income taxes 70,253 63,494 Unamortized investment tax credits 8,518 9,026 Other reserves and deferred credits 11,771 11,577 Commitments and contingencies (Note C) --------------------- $647,377 $555,907 ===================== The accompanying notes are an integral part of these financial statements.
The Narragansett Electric Company Statements of Cash Flows
- ------------------------------------------------------------------------------------------ Year Ended December 31, (In Thousands) 1994 1993 1992 - ------------------------------------------------------------------------------------------ Operating activities: Net income $ 14,589 $ 14,274 $ 21,052 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation 24,813 17,645 19,826 Deferred federal income taxes and investment tax credits - net 3,422 1,690 4,053 Allowance for funds used during construction (2,562) (1,132) (359) Amortization of unbilled revenues (6,158) Early retirement program 2,705 Decrease (increase) in accounts receivable, net and unbilled revenues (14,163) (2,183) (5,935) Decrease (increase) in fuel, materials, and (598) 429 3,281 supplies Decrease (increase) in prepaid and other current assets (2,478) 2,359 (12,786) Increase (decrease) in accounts payable 5,134 (3,180) 2,214 Increase (decrease) in other current liabilities 12,312 2,287 8,879 Other, net 5,877 (2,180) 404 ---------------------------------- Net cash provided by operating activities $ 40,188 $ 32,714 $ 40,629 ---------------------------------- Investing activities: Plant expenditures, excluding allowance for funds used during construction $(92,503) $(62,897) $(39,624) Other investing activities (911) Purchase of 90 percent interest in Manchester Street Station from affiliate 3,249 ---------------------------------- Net cash used in investing activities $(93,414) $(62,897) $(36,375) ---------------------------------- Financing activities: Capital contributions from NEES $ 15,000 $ 10,000 Dividends paid on common stock (2,831) $ (5,663) (4,530) Dividends paid on preferred stock (2,143) (1,783) (1,553) Changes in short-term debt 10,075 16,050 (11,850) Long-term debt - issues 33,000 27,500 67,500 Long-term debt - retirements (14,900) (62,200) Preferred stock - issues 20,000 Preferred stock - retirements (10,000) Premium on reacquisition of long-term debt (652) (1,645) Premium on redemption of preferred stock (361) Net cash provided by (used in) ---------------------------------- financing activities $ 53,101 $ 30,191 $ (4,278) ---------------------------------- Net increase (decrease) in cash and cash equivalents $ (125) $ 8 $ (24) Cash and cash equivalents at beginning of year 838 830 854 ---------------------------------- Cash and cash equivalents at end of year $ 713 $ 838 $ 830 ================================== Supplementary Information: Interest paid less amounts capitalized $ 14,015 $ 12,623 $ 12,365 ---------------------------------- Federal income taxes paid $ 2,982 $ 2,352 $ 4,005 ---------------------------------- The accompanying notes are an integral part of these financial statements.
The Narragansett Electric Company Notes to Financial Statements Note A - Significant Accounting Policies - ---------------------------------------- 1. System of Accounts: The accounts of the Company are maintained in accordance with the Uniform System of Accounts prescribed by regulatory bodies having jurisdiction. 2. Revenue: The Company, pursuant to its 1994 rate agreement, began accruing revenues for electricity delivered but not yet billed (unbilled revenues). Unbilled revenues at December 31, 1994 were $13 million, of which $5 million were recognized in income monthly in 1994. The remainder of $8 million at December 31, 1994 has been deferred for recognition monthly through December 1995 and appears on the balance sheet under the caption "Other accrued expenses". Accrued revenues are also recorded in accordance with rate adjustment mechanisms. 3. Allowance for Funds Used During Construction (AFDC): The Company capitalizes AFDC as part of construction costs. AFDC represents the composite interest and equity costs of capital funds used to finance that portion of construction costs not eligible for inclusion in rate base. In 1994, an average of $5 million of construction work in progress was included in rate base, all of which was attributable to the Manchester Street Station repowering project. AFDC is capitalized in "Utility plant" with offsetting non-cash credits to "Other income" and "Interest". This method is in accordance with an established rate-making practice under which a utility is permitted a return on, and the recovery of, prudently incurred capital costs through their ultimate inclusion in rate base and in the provision for depreciation. The composite AFDC rates were 6.8 percent, 6.9 percent, and 5.0 percent, in 1994, 1993, and 1992, respectively. 4. Depreciation: Depreciation is provided annually on a straight-line basis. The provisions for depreciation as a percentage of weighted average depreciable property were 4.5 percent, 3.5 percent, and 3.8 percent in 1994, 1993, and 1992, respectively. The increase in the depreciation rate in 1994 is primarily due to the recognition through depreciation expense of dismantlement costs for a retired generating facility. 5. Cash: The Company classifies short-term investments with a remaining maturity of 90 days or less as cash. Current banking arrangements do not require outstanding checks to be funded until actually presented for payment. Outstanding checks are therefore recorded in accounts payable until such time as the banks present them for payment. Note A - Significant Accounting Policies (continued) - ---------------------------------------- 6. Deferred Charges and Other Assets: The components of deferred charges and other assets are as follows: -------------------------------------------------------------------- At December 31, (In Thousands) 1994 1993 -------------------------------------------------------------------- Regulatory assets: Deferred SFAS No. 109 costs (see Note B) $26,999 $24,170 Unamortized losses on reacquired debt 12,538 13,383 Deferred SFAS No. 106 costs (see Note D-2) 5,539 4,053 Deferred storm costs 4,277 5,122 Other 3,751 3,750 -------------------- 53,104 50,478 Other deferred charges and other assets 4,623 3,231 -------------------- $57,727 $53,709 ==================== Electric utility rates are generally based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. These accounting rules require regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the income statement impact of certain costs that are expected to be recovered in future rates. The effects of competition could ultimately cause the operations of the Company, or a portion thereof, to cease meeting the criteria for application of these accounting rules. In such an event, accounting standards applicable to enterprises in general would apply and immediate write-off of any previously deferred costs (regulatory assets) would be necessary in the year in which these criteria were no longer applicable. Approximately $20 million of the regulatory assets at December 31, 1994 listed above are expected to be recovered within 10 years. All of the remainder will be fully recovered within the next 20 years with the exception of the Deferred SFAS No. 109 costs which will take longer to recover. Note B - Federal Income Taxes - ----------------------------- The Company and other subsidiaries participate with New England Electric System (NEES) in filing consolidated federal income tax returns. The Company's income tax provision is calculated on a separate return basis. Federal income tax returns have been examined and reported on by the Internal Revenue Service through 1991. Note B - Federal Income Taxes (continued) - ----------------------------- Federal income taxes consist of the following components: ------------------------------------------------------------------------- Year Ended December 31, (In Thousands) 1994 1993 1992 ------------------------------------------------------------------------- Income taxes charged to operations: Current income taxes $1,511 $2,537 $4,998 Deferred income taxes 3,880 2,146 4,493 Investment tax credits--net (508) (508) (507) ---------------------------- Total income taxes charged to operations 4,883 4,175 8,984 ---------------------------- Income taxes charged (credited) to "Other income": Current income taxes (491) (354) (390) Deferred income taxes 50 53 67 ---------------------------- Total income taxes charged (credited) to "Other income" (441) (301) (323) ---------------------------- Total federal income taxes $4,442 $3,874 $8,661 ============================ Investment tax credits are deferred and amortized over the estimated lives of the property giving rise to the credits. Since the Tax Reform Act of 1986 generally eliminated investment tax credits, the amounts shown above principally reflect the amortization of investment tax credits generated in prior years. Consistent with rate-making policies of the Rhode Island Public Utilities Commission (RIPUC), the Company has adopted comprehensive interperiod tax allocation (normalization) for most temporary book/tax differences. Total federal income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The reasons for the differences are as follows: -------------------------------------------------------------------------- Year Ended December 31, (In Thousands) 1994 1993 1992 -------------------------------------------------------------------------- Computed tax at statutory rate $ 6,661 $ 6,352 $10,102 Increases (reductions) in tax resulting from: Book versus tax depreciation not normalized 653 496 749 Costs associated with utility plant retirements deducted for tax purposes (1,872) (1,756) (1,257) Allowance for equity funds used during construction (360) (190) (3) Amortization of investment tax credits (508) (508) (508) Adjustment of prior year tax accruals (150) (473) All other differences 18 (47) (422) ---------------------------- Total federal income taxes $ 4,442 $ 3,874 $ 8,661 ============================ Effective federal income tax rate 23.3% 21.3% 29.1% ============================ Note B - Federal Income Taxes (continued) - ----------------------------- The Financial Accounting Standards Board established Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes" which became effective in 1993. The application of this new standard did not have a significant impact on 1993 or 1994 net income. The following table identifies the major components of total deferred income taxes: -------------------------------------------------------------------- At December 31, (In Millions) 1994 1993 -------------------------------------------------------------------- Deferred tax asset: Plant related $ 2 $ 2 Investment tax credits 3 3 All other 13 13 ------------------ 18 18 ------------------ Deferred tax liability: Plant related (57) (53) All other (31) (28) ------------------ (88) (81) ------------------ Net deferred tax liability $(70) $ (63) ================== There were no valuation allowances for deferred tax assets deemed necessary. The deferred taxes resulting from timing differences which appeared on the income statement in 1992 (prior to the adoption of SFAS No. 109 in 1993) primarily included deferred income taxes of $3 million in connection with postretirement benefits other than pensions and $2 million related to utility plant, partially offset by deferred tax credits of $1 million associated with rate adjustment mechanisms. Note C - Commitments and Contingencies - -------------------------------------- 1. Plant Expenditures: The Company's utility plant expenditures are estimated to be $55 million in 1995. At December 31, 1994, substantial commitments had been made relative to future planned expenditures. 2. Hazardous Waste: The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by-products. NEES subsidiaries currently have in place an environmental audit program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. The Company has been named as a potentially responsible party (PRP) by either the U.S. Environmental Protection Agency or the Massachusetts Department of Environmental Protection for two sites (one of which is located in Massachusetts) at which hazardous waste is alleged to have been disposed. The Company is currently aware of other sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. Gas was manufactured from coal in Rhode Island in the past. The Company is aware of five sites on which gas was manufactured or manufactured gas was stored that were owned either by the Company or by its predecessor companies. It is not known to what extent the Company would be held liable for hazardous wastes, if any, left at these manufactured gas locations. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. A preliminary review by a consultant hired by the NEES companies of the potential cost of investigating and, if necessary, remediating Rhode Island manufactured gas sites resulted in costs per site ranging from less than $1 million to $8 million. An informal survey of other utilities conducted on behalf of NEES and its subsidiaries indicated costs in a similar range. Where appropriate, the Company intends to seek recovery from its insurers and from other PRPs, but it is uncertain whether and to what extent such efforts would be successful. The Company believes that hazardous waste liabilities for all sites of which it is aware will not be material to its financial position. 3. 1991 Rhode Island Filled Land Legislation: The Company's title to properties which may be situated on filled lands (including substations) has been called into question by a 1991 Rhode Island Supreme Court case dealing with title to filled land. The Company's title to the land on which the Manchester Street Station property is located was cleared by legislation in July 1992, by the Rhode Island legislature. The Company is challenging the 1991 ruling with respect to another parcel of property. Note D - Employee Benefits - -------------------------- 1. Pension Plans: The Company participates with other subsidiaries of NEES in noncontributory defined-benefit plans covering substantially all employees of the Company. The plans provide pension benefits based on the employee's compensation during the five years before retirement. The Company's funding policy is to contribute each year, the net periodic pension cost for that year. However, the contribution for any year will not be less than the minimum required contribution under federal law or greater than the maximum tax deductible amount. Net pension cost for 1994, 1993, and 1992 included the following components: ------------------------------------------------------------------------- Year Ended December 31, (In Thousands) 1994 1993 1992 ------------------------------------------------------------------------- Service cost-benefits earned during the period $ 1,877 $ 1,557 $ 1,558 Plus (less): Interest cost on projected benefit obligation 8,629 8,737 8,261 Return on plan assets at expected long-term rate (9,024) (8,739) (8,572) Amortization 567 (101) (125) ---------------------------- Net pension cost $ 2,049 $ 1,454 $ 1,122 ============================ Assumptions used to determine pension cost: Discount rate 7.25% 8.25% 8.50% Average rate of increase in future compensation levels 4.35% 5.35% 6.70% Expected long-term rate of return on assets 8.75% 8.75% 9.00% ---------------------------- Actual return on plan assets $ 809 $13,545 $ 7,570 ============================ Service cost for 1993 does not reflect costs incurred in connection with an early retirement program offered by the Company in that year (see Note D-3). The funded status of the plans cannot be presented separately for the Company as the Company participates in the plans with other NEES subsidiaries. The following table sets forth the funded status of the NEES companies' plans at December 31: Note D - Employee Benefits (continued) - -------------------------- ------------------------------------------------------------------------- Retirement Plans (In Millions) 1994 1993 --------------------------------------------------------------------------- Union Non-Union Union Non-Union Employee Employee Employee Employee Plans Plans Plans Plans ---------------------------------------- Benefits earned Actuarial present value of accumulated benefit liability: Vested $251 $308 $251 $333 Non-vested 8 9 20 6 -------------------------------------- Total $259 $317 $271 $339 ====================================== Reconciliation of funded status Actuarial present value of projected benefit liability $303 $355 $310 $383 Unrecognized prior service costs (8) (4) (8) (6) SFAS No. 87 transition liability not yet recognized (amortized) - (1) - (1) Net loss not yet recognized (amortized) (13) (33) (11) (45) Additional minimum liability recognized - - - 8 -------------------------------------- 282 317 291 339 -------------------------------------- Pension fund assets at fair value 293 323 302 318 SFAS No. 87 transition asset not yet recognized (amortized) (13) - (14) - -------------------------------------- 280 323 288 318 -------------------------------------- Accrued pension/(prepaid) payments recorded on books $ 2 $ (6) $ 3 $ 21 ====================================== The assumed discount rate and the assumed average rate of increase in future compensation levels used to calculate pension cost changed effective January 1, 1995 to 8.25 percent and 4.63 percent, respectively. The expected long-term rate of return on assets used to calculate pension cost was not changed from the level shown in the table above. The plans' funded status at December 31, 1994 was calculated using these revised rates. Plan assets are composed primarily of corporate equity, guaranteed investment contracts, debt securities, and cash equivalents. 2. Postretirement Benefit Plans Other Than Pensions and Postemployment Benefits: In 1993, SFAS No. 106, "Employer's Accounting for Postretirement Benefits Other Than Pensions" (PBOPs) went into effect. The Company provides health care and life insurance coverage to eligible retired employees. Note D - Employee Benefits (continued) - -------------------------- Eligibility is based on certain age and length of service requirements and in some cases retirees must contribute to the cost of their coverage. The total cost of PBOPs for 1994 and 1993 included the following components: -------------------------------------------------------------------- Year Ended December 31, (In Thousands) 1994 1993 -------------------------------------------------------------------- Service cost--benefits earned during the period $ 1,252 $ 1,161 Plus (less): Interest cost on the accumulated benefit obligation 5,630 6,330 Return on plan assets at expected long-term rate (1,640) (1,031) Amortization 3,716 3,864 --------------------- Net postretirement benefit cost $ 8,958 $10,324 ===================== Actual return (loss) on plan assets $ (23) $ 1,047 ===================== The following table sets forth benefits earned and the plans' funded status: ----------------------------------------------------------------------- At December 31, (In Millions) 1994 1993 ----------------------------------------------------------------------- Accumulated postretirement benefit obligation: Retirees $ 50 $ 54 Fully eligible active plan participants 10 7 Other active plan participants 14 22 ------------------ Total benefits earned 74 83 Unrecognized transition obligation (70) (74) Net gain (loss) not yet recognized 10 (1) ------------------ 14 8 Plan assets at fair value 22 17 ------------------ Prepaid postretirement benefit costs recorded on books $ 8 $ 9 ================== ---------------------------------------------------------------------- 1995 1994 1993 ---------------------------------------------------------------------- Assumptions used to determine postretirement benefit cost: Discount rate 8.25% 7.25% 8.25% Expected long-term rate of return on assets 8.50% 8.50% 8.50% Health care cost rate - 1994 and 1993 - 11.00% 12.00% Health care cost rate - 1995 to 2004 8.50% 8.50% 9.50% Health care cost rate - 2005 and beyond 6.25% 6.25% 7.25% Note D - Employee Benefits (continued) - -------------------------- The plans' funded status at December 31,1994 and 1993 presented above was calculated using the assumed rates in effect for 1995 and 1994, respectively. The health care cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed rates by 1 percent in each year would increase the accumulated postretirement benefit obligation as of December 31, 1994 by approximately $11 million and the net periodic cost for the year 1994 by approximately $1.2 million. The Company funds the annual tax deductible contributions. Plan assets are invested in equity and debt securities and cash equivalents. Prior to 1993, the Company recorded the cost of PBOPs when paid. These costs amounted to approximately $3.0 million in 1992. The Company has been permitted by the RIPUC to phase-in over a three year period that commenced January 1, 1993, a level of rate recovery that is expected to equal or exceed the amount of PBOP costs calculated in accordance with SFAS No. 106. At December 31, 1994, the Company had deferred for recovery over a seven year period commencing January 1, 1996, $6 million, representing that portion of increased PBOP costs not being recovered during this phase-in period. Therefore, adoption of this new accounting standard did not have a significant impact on net income. In the fourth quarter of 1993, the Company recorded a $1 million charge to earnings reflecting the cumulative effect of adopting a new accounting standard for postemployment benefits. 3. 1993 Early Retirement and Special Severance Programs: In February 1993, the Company offered a voluntary early retirement program to non-union employees who were at least 55 years old with 10 years of service. This program was part of an organizational review with the goal of streamlining operations and reducing the work force. The early retirement offer was accepted by 46 employees. A special severance program was also announced in February 1993 for employees affected by the organizational review, but who were not eligible for, or did not accept, the early retirement offer. The Company recorded in the first quarter of 1993 a one-time charge to earnings of approximately $3 million, after tax ($5 million, before tax), to reflect the cost of the early retirement and special severance programs which consisted principally of pension benefits. This total includes the Company's portion of its affiliated service company's cost of these programs. Note E - Short-term Borrowing Arrangements - ------------------------------------------ At December 31, 1994, the Company had $30 million of short-term debt outstanding in the form of commercial paper borrowings. At December 31, 1994, the Company had lines of credit with banks totaling $41 million. There were no borrowings under these lines of credit at December 31, 1994. Fees are paid in lieu of compensating balances on most lines of credit. The weighted average rate on outstanding short-term borrowings was 6.1 percent at December 31, 1994. Note F - Intercompany Lending Arrangement - ----------------------------------------- NEES and certain subsidiaries, including the Company, with regulatory approval, operate a money pool to more effectively utilize cash resources and to reduce outside short-term borrowings. Short-term borrowing needs are met first by available funds of the money pool participants. Borrowing companies pay interest at a rate designed to approximate the cost of outside short-term borrowings. Companies which invest in the pool share the interest earned on a basis proportionate to their average monthly investment in the money pool. Funds may be withdrawn from or repaid to the pool at any time without prior notice. Note G - Cumulative Preferred Stock - ----------------------------------- A summary of cumulative preferred stock at December 31, 1994 and 1993 is as follows (in thousands of dollars except for share data): Shares Authorized and Dividends Call Outstanding Amount Declared Price ------------------------------------------------------------------------- 1994 1993 1994 1993 1994 1993 ------------------------------------------------------------------------- $50 Par value-- 4.50% Series 180,000 180,000 $ 9,000 $ 9,000 $ 405 $ 405 $55.000 4.64% Series 150,000 150,000 7,500 7,500 348 348 52.125 6.95% Series 400,000 400,000 20,000 20,000 1,390 710 (a) 8.00% Series 468 -------------------------------------------------- Total 730,000 730,000 $36,500 $36,500 $2,143 $1,931 ================================================== (a) Callable on or after August 1, 2003 at $51.74. The annual dividend requirement for total cumulative preferred stock was $2,143,000 for 1994 and 1993. During 1993, all of the Company's 8.00 percent Series of cumulative preferred stock were redeemed. Total premiums of $361,000 in connection with this redemption were charged to retained earnings in 1993. There are no mandatory redemption provisions on the Company's cumulative preferred stock. Note H - Long-term Debt - ----------------------- A summary of long-term debt is as follows: At December 31, (In Thousands) ------------------------------------------------------------- Series Rate % Maturity 1994 1993 ------------------------------------------------------------- First Mortgage Bonds: U (92-1) 7.230 June 3, 1997 $ 10,000 $ 10,000 U (92-2) 7.210 June 3, 1997 5,000 5,000 U (92-3) 7.000 June 16, 1997 10,000 10,000 U (92-7) 5.700 September 16, 1997 7,500 7,500 V (94-2) 6.960 May 3, 1999 2,000 V (94-3) 6.910 May 4, 1999 1,000 U (92-6) 6.630 August 12, 1999 5,000 5,000 U (92-5) 6.980 July 17, 2000 5,000 5,000 U (92-8) 6.340 September 18, 2000 10,000 10,000 U (92-4) 7.830 June 17, 2002 15,000 15,000 U (93-1) 7.080 January 13, 2003 7,500 7,500 U (93-2) 6.560 April 15, 2003 5,000 5,000 U (93-4) 6.350 July 1, 2003 5,000 5,000 V (94-4) 7.420 June 15, 2004 5,000 V (94-6) 8.330 November 8, 2004 10,000 U (93-3) 6.650 June 30, 2008 5,000 5,000 S 9.125 May 1, 2021 22,200 22,200 T 8.875 August 1, 2021 40,000 40,000 U (93-5) 7.050 September 1, 2023 5,000 5,000 U (94-1) 7.050 February 2, 2024 5,000 V (94-1) 8.080 May 2, 2024 5,000 V (94-5) 8.160 August 9, 2024 5,000 Unamortized discounts and premiums (1,338) (1,228) ------------------- Total long-term debt $188,862 $155,972 =================== Substantially all of the properties and franchises of the Company are subject to the lien of the mortgage indentures under which first mortgage bonds have been issued. The Company will make cash payments of $32,500,000 in 1997 and $8,000,000 in 1999 to retire maturing mortgage bonds. There are no cash payments required in 1995, 1996, and 1998. Note I - Fair Value of Financial Instruments - -------------------------------------------- At December 31, 1994, the Company's long-term debt had a carrying value of approximately $189,000,000 and had a fair value of approximately $183,000,000. The fair market value of the Company's long-term debt was estimated based on the quoted prices for similar issues or on the current rates offered to the Company for debt of the same remaining maturity. The fair value of the Company's short-term debt equals carrying value. Note J - Restrictions on Retained Earnings Available for Dividends on Common Stock - --------------------------------------------------------------------- As long as any preferred stock is outstanding, certain restrictions on payment of dividends on common stock would come into effect if the "junior stock equity" was, or by reason of payment of such dividends became less than 25 percent of "total capitalization". However, the junior stock equity at December 31, 1994 was 48 percent of total capitalization and, accordingly, none of the Company's retained earnings at December 31, 1994 were restricted as to dividends on common stock under the foregoing restrictions. Under restrictions contained in the indentures relating to first mortgage bonds, none of the Company's retained earnings at December 31, 1994 were restricted as to dividends on common stock. Note K - Regulatory Matters - --------------------------- A 1986 Rhode Island Supreme Court decision held that the RIPUC's rate-making powers include the authority to order refunds of amounts earned in excess of an allowed return. As a result, the RIPUC monitors the Company's earnings on a regular basis. Note L - Supplementary Income Statement Information - --------------------------------------------------- Advertising expenses, expenditures for research and development, and rents were not material and there were no royalties paid. Taxes, other than federal income taxes, charged to operating expenses are set forth by classes as follows: ----------------------------------------------------------------------- Year Ended December 31, (In Thousands) 1994 1993 1992 ----------------------------------------------------------------------- Municipal property taxes $13,944 $13,798 $13,509 State gross earnings tax 19,270 19,281 18,730 Federal and state payroll and other taxes 2,604 2,767 2,933 ---------------------------- $35,818 $35,846 $35,172 ============================ New England Power Service Company, an affiliated service company operating pursuant to the provisions of Section 13 of the Public Utility Holding Company Act of 1935, furnished services to the Company at the cost of such services. These costs amounted to $32,445,000, $30,133,000, and $23,543,000 including capitalized construction costs of $7,756,000, $6,602,000, and $5,436,000 for each of the years 1994, 1993, and 1992, respectively. The Narragansett Electric Company Operating Statistics (Unaudited)
- ------------------------------------------------------------------------------------------ Year Ended December 31, 1994 1993 1992 1991 1990 - ------------------------------------------------------------------------------------------ Sources of Energy (Thousands of KWH) Net generation for New England Power Company 5,781 4,506 83,753 162,844 583,413 Purchased energy: From New England Power Company, an affiliate (net of generation) 5,001,843 4,982,254 4,729,733 4,699,509 4,272,537 From others 2,909 2,343 2,249 2,243 1,556 -------------------------------------------------------- Total generated and purchased 5,010,533 4,989,103 4,815,735 4,864,596 4,857,506 Losses, company use, etc. (263,234) (270,373) (229,106) (277,383) (265,328) -------------------------------------------------------- Total sources of energy 4,747,299 4,718,730 4,586,629 4,587,213 4,592,178 ======================================================== Sales of Energy (Thousands of KWH) Residential 1,843,970 1,817,675 1,783,754 1,784,156 1,794,215 Commercial 1,983,508 1,931,377 1,877,738 1,867,225 1,879,587 Industrial 868,092 917,305 869,062 878,142 858,675 Other 51,138 51,821 55,476 57,106 59,099 -------------------------------------------------------- Total sales to ultimate customers 4,746,708 4,718,178 4,586,030 4,586,629 4,591,576 Sales for resale 591 552 599 584 602 -------------------------------------------------------- Total sales of energy 4,747,299 4,718,730 4,586,629 4,587,213 4,592,178 ======================================================== Annual Maximum Demand (Kw - one hour peak) 1,005,000 939,000 919,000 961,000 940,000 Average Annual Use per Residential Customer (KWH) 6,397 6,337 6,265 6,308 6,387 Number of Customers at December 31 Residential 289,317 287,876 286,228 284,275 282,314 Commercial 32,195 31,948 31,534 31,417 31,591 Industrial 1,825 1,869 1,914 1,944 1,983 Other 875 878 941 934 906 -------------------------------------------------------- Total ultimate customers 324,212 322,571 320,617 318,570 316,794 Other electric companies (for resale) 2 1 3 4 3 -------------------------------------------------------- Total customers 324,214 322,572 320,620 318,574 316,797 ======================================================== Operating Revenue (In Thousands) Residential $201,221 $202,522 $196,983 $192,688 $172,804 Commercial 189,633 190,185 183,702 178,616 162,013 Industrial 72,364 78,088 76,275 76,299 68,644 Other 6,905 6,778 6,587 6,197 5,500 -------------------------------------------------------- Total revenue from ultimate customers 470,123 477,573 463,547 453,800 408,961 Unbilled revenues 4,891 Sales for resale 68 64 68 65 62 -------------------------------------------------------- Total revenue from electric sales 475,082 477,637 463,615 453,865 409,023 Other operating revenue 6,587 5,391 4,637 3,645 3,250 -------------------------------------------------------- Total operating revenue $481,669 $483,028 $468,252 $457,510 $412,273 ========================================================
The Narragansett Electric Company Selected Financial Information
- --------------------------------------------------------------------------------------- Year Ended December 31, (In Millions) 1994 1993 1992 1991 1990 - --------------------------------------------------------------------------------------- Operating revenue: Electric sales (excluding fuel cost recovery) $356 $351 $342 $340 $308 Fuel cost recovery 120 127 121 114 101 Other 6 5 5 4 3 ------------------------------------------ Total operating revenue $482 $483 $468 $458 $412 Net income $ 15 $ 14 $ 21 $ 17 $ 18 Total assets $647 $556 $479 $445 $421 Capitalization: Common equity $208 $183 $176 $151 $136 Cumulative preferred stock 37 37 27 27 27 Long-term debt 189 156 143 118 112 ------------------------------------------ Total capitalization $434 $376 $346 $296 $275 Preferred dividends declared $ 2 $ 2 $ 2 $ 2 $ 2 Common dividends declared $ 3 $ 5 $ 5 $ 5 $ 8
Selected Quarterly Financial Information (Unaudited)
- --------------------------------------------------------------------------------------- First Second Third Fourth (In Thousands) Quarter Quarter Quarter Quarter - --------------------------------------------------------------------------------------- 1994 Operating revenue $125,461 $103,800 $137,014 $115,394 Operating income $ 10,407 $ 2,714 $ 10,937 $ 6,056 Net income (loss) $ 6,314 $ (1,013) $ 7,230 $ 2,058 1993 Operating revenue $124,147 $107,529 $136,174 $115,178 Operating income $ 8,220 $ 3,937 $ 9,761 $ 6,647 Net income $ 3,800 $ 493 $ 6,435 $ 3,546 Per share data is not relevant because the Company's common stock is wholly-owned by New England Electric System. A copy of The Narragansett Electric Company's Annual Report on Form 10-K to the Securities and Exchange Commission, for the year ended December 31, 1994, will be available on or about April 1, 1995, without charge, upon written request to The Narragansett Electric Company, Shareholder Services Department, 280 Melrose Street, Providence, Rhode Island 02901.
EX-24 21 EXHIBIT 24 POWER OF ATTORNEY Each of the undersigned directors of The Narragansett Electric Company (the "Company"), individually as a director of the Company, hereby constitutes and appoints John G. Cochrane, Thomas F. Killeen, and Geraldine M. Zipser, individually, as attorney-in-fact to execute on behalf of the undersigned the Company's annual report on Form 10-K for the year ended December 31, 1994, to be filed with the Securities and Exchange Commission, and to execute any appropriate amendment or amendments thereto as may be required by law. Dated this 28th day of March, 1995. Joan T. Bok John W. Rowe s/ Stephen A. Cardi s/ Richard P. Sergel Stephen A. Cardi Richard P. Sergel s/ Frances H. Gammell s/ William E. Trueheart Frances H. Gammell William E. Trueheart s/ Joseph J. Kirby s/ John A. Wilson, Jr. Joseph J. Kirby John A. Wilson, Jr. s/ Robert L. McCabe Robert L. McCabe EX-27 22 EXHIBIT 27 WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT 1,000 DEC-31-1994 DEC-31-1993 DEC-31-1994 DEC-31-1993 12-MOS 12-MOS PER-BOOK PER-BOOK 491,915 421,577 0 0 97,735 80,621 57,727 53,709 0 0 647,377 555,907 56,624 56,624 60,170 45,170 91,556 81,659 208,350 183,453 0 0 36,500 36,500 188,862 155,972 29,800 19,725 0 0 0 0 0 0 0 0 0 0 0 0 183,865 160,257 647,377 555,907 481,669 483,028 4,883 4,175 446,672 450,288 451,555 454,463 30,114 28,565 172 (91) 30,286 28,474 15,697 14,200 14,589 14,274 2,143 1,931 12,446 11,982 2,549 4,530 14,334 12,715 40,188 32,714 0 0 0 0 Total deferred charges includes other assets. Short-term notes includes commercial paper borrowings. Short-term notes at December 31, 1993 also includes short-term debt to affiliates. -----END PRIVACY-ENHANCED MESSAGE-----