-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Utov1S5DUdMZWv+ckiGl6cRQjyC00DM47V1dGKL0njJq6H8ucYf/kd/r3i4zLbN7 K3vSYv1LfStPMVO89k3FNA== 0000072741-98-000130.txt : 19980615 0000072741-98-000130.hdr.sgml : 19980615 ACCESSION NUMBER: 0000072741-98-000130 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980612 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHEAST UTILITIES SYSTEM CENTRAL INDEX KEY: 0000072741 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 042147929 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: SEC FILE NUMBER: 001-05324 FILM NUMBER: 98647034 BUSINESS ADDRESS: STREET 1: 174 BRUSH HILL AVE CITY: WEST SPRINGFIELD STATE: MA ZIP: 01090-0010 BUSINESS PHONE: 4137855871 MAIL ADDRESS: STREET 1: 107 SELDON ST CITY: BERLIN STATE: CT ZIP: 06037-1616 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONNECTICUT LIGHT & POWER CO CENTRAL INDEX KEY: 0000023426 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 060303850 STATE OF INCORPORATION: CT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: SEC FILE NUMBER: 000-00404 FILM NUMBER: 98647035 BUSINESS ADDRESS: STREET 1: SELDEN STREET CITY: BERLIN STATE: CT ZIP: 06037-1616 BUSINESS PHONE: 8606655000 FILER: COMPANY DATA: COMPANY CONFORMED NAME: WESTERN MASSACHUSETTS ELECTRIC CO CENTRAL INDEX KEY: 0000106170 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041961130 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: SEC FILE NUMBER: 012-00091 FILM NUMBER: 98647036 BUSINESS ADDRESS: STREET 1: 174 BRUSH HILL AVE CITY: WEST SPRINGFIELD STATE: MA ZIP: 01090-0010 BUSINESS PHONE: 4137855871 MAIL ADDRESS: STREET 1: 107 SELDON ST CITY: BERLIN STATE: CT ZIP: 06037-1616 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PUBLIC SERVICE CO OF NEW HAMPSHIRE CENTRAL INDEX KEY: 0000315256 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 020181050 STATE OF INCORPORATION: NH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: SEC FILE NUMBER: 012-00093 FILM NUMBER: 98647037 BUSINESS ADDRESS: STREET 1: 1000 ELM ST CITY: MANCHESTER STATE: NH ZIP: 03105 BUSINESS PHONE: 6036694000 MAIL ADDRESS: STREET 1: 107 SELDON ST CITY: BERLIN STATE: CT ZIP: 06037-1616 10-K/A 1 FORM 10-K/A (AMENDMENT NO. 1) SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549-1004 [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended DECEMBER 31, 1997 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission Registrant; State of Incorporation; I.R.S Employer File Number Address; and Telephone Number Identification No. 1-5324 NORTHEAST UTILITIES 04-2147929 (a Massachusetts voluntary association) 174 BRUSH HILL AVENUE WEST SPRINGFIELD, MASSACHUSETTS 01090-2010 Telephone: (413) 785-5871 0-11419 THE CONNECTICUT LIGHT AND POWER COMPANY 06-0303850 (a Connecticut corporation) 107 SELDEN STREET BERLIN, CONNECTICUT 06037-1616 Telephone: (860) 665-5000 1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 02-0181050 (a New Hampshire corporation) 1000 ELM STREET MANCHESTER, NEW HAMPSHIRE 03105-0330 Telephone: (603) 669-4000 0-7624 WESTERN MASSACHUSETTS ELECTRIC COMPANY 04-1961130 (a Massachusetts corporation) 174 BRUSH HILL AVENUE WEST SPRINGFIELD, MASSACHUSETTS 01090-2010 Telephone: (413) 785-5871 Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange Registrant Title of Each Class on Which Registered NORTHEAST UTILITIES Common Shares, $5.00 New York Stock Exchange, Inc. par value THE CONNECTICUT LIGHT 9.3% Cumulative New York Stock Exchange, Inc. AND POWER COMPANY Monthly Income Preferred Securities Series A (1) (1) Issued by CL&P Capital, L.P., a wholly owned subsidiary of The Connecticut Light and Power Company ("CL&P"), and guaranteed by CL&P. Securities registered pursuant to Section 12(g) of the Act: Registrant Title of Each Class THE CONNECTICUT LIGHT Preferred Stock, par value $50.00 per share, AND POWER COMPANY issuable in series, of which the following series are outstanding: $1.90 Series of 1947 4.96% Series of 1958 $2.00 Series of 1947 4.50% Series of 1963 $2.04 Series of 1949 5.28% Series of 1967 $2.20 Series of 1949 6.56% Series of 1968 3.90% Series of 1949 $3.24 Series G of 1968 $2.06 Series E of 1954 7.23% Series of 1992 $2.09 Series F of 1955 5.30% Series of 1993 4.50% Series of 1956 PUBLIC SERVICE Preferred Stock, par value $25.00 per share, COMPANY OF issuable in series, of which the following series NEW HAMPSHIRE are outstanding: 10.60% Series A of 1991 WESTERN MASSACHUSETTS Preferred Stock, par value $100.00 per share, ELECTRIC COMPANY issuable in series, of which the following series is outstanding: 7.72% Series B of 1971 Class A Preferred Stock, par value $25.00 per share, issuable in series, of which the following series are outstanding: 7.60% Series of 1987 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. YES X 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 the 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 aggregate market value of NORTHEAST UTILITIES' Common Share, $5.00 Par Value, held by nonaffiliates, was $2,181,626,490 based on a closing sales price of $15.94 per share for the 136,886,368 common shares outstanding on May 29, 1998. NORTHEAST UTILITIES holds all of the 12,222,930 shares, 1,000 shares and 1,072,471 shares of the outstanding common stock of THE CONNECTICUT LIGHT AND POWER COMPANY, PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND WESTERN MASSACHUSETTS ELECTRIC COMPANY, respectively. Documents Incorporated by Reference: Part of Form 10-K into Which Document Description is Incorporated Portions of Annual Reports to Shareholders of the following companies for the year ended December 31, 1997: Northeast Utilities Part II The Connecticut Light and Power Company Part II Public Service Company of New Hampshire Part II Western Massachusetts Electric Company Part II Explanatory Note: Securities and Exchange Commission Inquiry and Amendment of the Form 10-Ks of NU, CL&P, PSNH and WMECO In a letter dated March 25, 1998, the SEC inquired into the NU system's accounting for nuclear compliance costs. These costs are the unavoidable incremental costs associated with the current nuclear outages required to be incurred prior to restart of the units in accordance with correspondence received from the NRC early in 1996. The SEC's view is that these unavoidable costs associated with nuclear outages and procedures to be implemented at nuclear power plants in response to regulatory requirements required prior to restart of the units should be expensed as incurred. During 1996 and 1997, NU, CL&P, PSNH and WMECO reserved for these unavoidable incremental costs that they expected to incur to meet NRC standards. The SEC advised NU, CL&P, PSNH and WMECO to reflect these costs as they are incurred. While NU and its independent auditors, Arthur Andersen LLP, believed the accounting was required by, and was in accordance with, generally accepted accounting principles, the company has agreed to adjust its accounting for nuclear compliance costs and amend its 1996 and 1997 Form 10-K filings. This amendment on Form 10-K/A reflects the change in accounting. GLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report: NU.............................. Northeast Utilities CL&P............................ The Connecticut Light and Power Company Charter Oak or COE.............. Charter Oak Energy, Inc. WMECO........................... Western Massachusetts Electric Company HWP............................. Holyoke Water Power Company NUSCO or the Service Company.... Northeast Utilities Service Company NNECO........................... Northeast Nuclear Energy Company NAEC............................ North Atlantic Energy Corporation NAESCO or North Atlantic........ North Atlantic Energy Service Corporation PSNH............................ Public Service Company of New Hampshire RRR............................. The Rocky River Realty Company Select Enery.................... Select Energy, Inc., formerly NUSCO Energy Partners, Inc. Mode 1.......................... Mode 1 Communications, Inc. HEC............................. HEC Inc. Quinnehtuk...................... The Quinnehtuk Company the System...................... The Northeast Utilities System CYAPC........................... Connecticut Yankee Atomic Power Company MYAPC........................... Maine Yankee Atomic Power Company VYNPC........................... Vermont Yankee Nuclear Power Corporation YAEC............................ Yankee Atomic Electric Company the Yankee Companies............ CYAPC, MYAPC, VYNPC, and YAEC GENERATING UNITS Millstone 1..................... Millstone Unit No. 1, a 660-MW nuclear generating unit completed in 1970 Millstone 2..................... Millstone Unit No. 2, an 870-MW nuclear electric generating unit completed in 1975 Millstone 3..................... Millstone Unit No. 3, a 1,154-MW nuclear electric generating unit completed in 1986 Seabrook or Seabrook 1.......... Seabrook Unit No. 1, a 1,148-MW nuclear electric generating unit completed in 1986. Seabrook 1 went into service in 1990. REGULATORS DOE............................. U.S. Department of Energy DTE............................. Massachusetts Department of Telecommunications and Energy, formerly the Massachusetts Department of Public Utilities (DPU) DPUC............................ Connecticut Department of Public Utility Control MDEP............................ Massachusetts Department of Environmental CDEP............................ Connecticut Department of Environmental Protection EPA............................. U.S. Environmental Protection Agency FERC............................ Federal Energy Regulatory Commission NHDES........................... New Hampshire Department of Environmental Services NHPUC........................... New Hampshire Public Utilities Commission NRC............................. Nuclear Regulatory Commission SEC............................. Securities and Exchange Commission OTHER 1935 Act........................ Public Utility Holding Company Act of 1935 CAAA............................ Clean Air Act Amendments of 1990 DSM............................. Demand-Side Management Energy Act...................... Energy Policy Act of 1992 EWG............................. Exempt wholesale generator EAC............................. Energy Adjustment Clause (CL&P) FAC............................. Fuel Adjustment Clause (WMECO) FPPAC........................... Fuel and purchased power adjustment clause (PSNH) FUCO............................ Foreign utility company kWh............................. Kilowatt-hour MW.............................. Megawatt NBFT............................ Niantic Bay Fuel Trust, lessor of nuclear fuel used by CL&P and WMECO ISO............................. Independent System Operator, successor to the New England Power Pool (NEPOOL) NEPOOL.......................... New England Power Pool NUGs............................ Nonutility generators NUG&T........................... Northeast Utilities Generation and Transmission Agreement NORTHEAST UTILITIES THE CONNECTICUT LIGHT AND POWER COMPANY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE WESTERN MASSACHUSETTS ELECTRIC COMPANY 1997 Form 10-K/A Annual Report Table of Contents PART II Page Item 6. Selected Financial Data...................................... 1 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.......................... 1 Item 8. Financial Statements and Supplementary Data.................. 1 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.......................................... 3 Item 6. Selected Financial Data NU. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 65 of NU's Amended 1997 Annual Report to Shareholders, which information is incorporated herein by reference. CL&P. Reference is made to information under the heading "Selected Financial Data" contained on page 54 of CL&P's Amended 1997 Annual Report, which information is incorporated herein by reference. PSNH. Reference is made to information under the heading "Selected Financial Data" contained on pages 50 and 51 of PSNH's Amended 1997 Annual Report, which information is incorporated herein by reference. WMECO. Reference is made to information under the heading "Selected Financial Data" contained on page 51 of WMECO's Amended 1997 Annual Report, which information is incorporated herein by reference. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations NU. Reference is made to information under the heading "Management's Discussion and Analysis" contained on pages 48 through 63 in NU's Amended 1997 Annual Report to Shareholders, which information is incorporated herein by reference. CL&P. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 42 through 53 in CL&P's Amended 1997 Annual Report, which information is incorporated herein by reference. PSNH. Reference is made toinformation under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 42 through 49 in PSNH's Amended 1997 Annual Report, which information is incorporated herein by reference. WMECO. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 40 through 50 in WMECO's Amended 1997 Annual Report, which information is incorporated herein by reference. Item 8. Financial Statements and Supplementary Data NU. Reference is made to information under the headings "Company Report," "Report of Independent Public Accountants," "Consolidated Statements of Income," "Consolidated Statements of Cash Flows," "Consolidated Statements of Income Taxes," "Consolidated Balance Sheets," "Consolidated Statements of Capitalization," "Consolidated Statements of Common Shareholders' Equity," "Notes to Consolidated Financial Statements," and "Consolidated Statements of Quarterly Financial Data" contained on pages 2 through 47 and page 64 in NU's Amended 1997 Amended Report to Shareholders, which information is incorporated herein by reference. CL&P. Reference is made to information under the headings "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Cash Flows," "Consolidated Statements of Common Stockholder's Equity," "Notes to Consolidated Financial Statements," "Report of Independent Public Accountants," and "Statements of Quarterly Financial Data" contained on pages 2 through 41 and page 54 in CL&P's Amended 1997 Annual Report, which information is incorporated herein by reference. PSNH. Reference is made to information under the headings "Balance Sheets," "Statements of Income," "Statements of Cash Flows," "Statements of Common Equity," "Notes to Financial Statements," "Report of Independent Public Accountants," and "Statements of Quarterly Financial Data" contained on pages 2 through 41 and page 52 in PSNH's Amended 1997 Annual Report, which information is incorporated herein by reference. WMECO. Reference is made to information under the headings "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Cash Flows," "Consolidated Statements of Common Stockholder's Equity," "Notes to Consolidated Financial Statements," "Report of Independent Public Accountants," and "Statements of Quarterly Financial Data" contained on pages 2 through 39 and page 51 in WMECO's Amended 1997 Annual Report, which information is incorporated herein by reference. Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K. (a) 1. Financial Statements: The Report of Independent Public Accountants and financial statements of NU, CL&P, PSNH and WMECO are hereby incorporated by reference and made a part of this report (see "Item 8. Financial Statements and Supplementary Data"). Report of Independent Public Accountants on Schedules S-1 Consent of Independent Public Accountants S-3 2. Schedules: Amended Financial Statement Schedules for NU (Parent), NU and Subsidiaries, CL&P and Subsidiaries, PSNH and WMECO and Subsidiary are listed in the Index to Financial Statements Schedules S-4 3. Exhibits Index E-1 NORTHEAST UTILITIES SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. NORTHEAST UTILITIES (Registrant) Date: June 10, 1998 By: /s/ Michael G. Morris Michael G. Morris Chairman of the Board and President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Date Title Signature June 10, 1998 Chairman of the Board, /s/ Michael G. Morris President and Michael G. Morris Chief Executive Officer and a Trustee June 10, 1998 Executive Vice /s/ John H. Forsgren President and Chief John H. Forsgren Financial Officer June 10, 1998 Vice President and /s/ John J. Roman Controller John J. Roman NORTHEAST UTILITIES SIGNATURES (CONT'D) Date Title Signature June 10, 1998 Trustee /s/ Cotton M. Cleveland Cotton M. Cleveland June 10, 1998 Trustee /s/ William F. Conway William F. Conway June 10, 1998 Trustee /s/ E. Gail de Planque E. Gail de Planque June 10, 1998 Trustee /s/ Elizabeth T. Kennan Elizabeth T. Kennan June 10, 1998 Trustee /s/ William J. Pape II William J. Pape II June 10, 1998 Trustee /s/ Robert E. Patricelli Robert E. Patricelli June 10, 1998 Trustee /s/ John F. Swope John F. Swope June 10, 1998 Trustee /s/ John F. Turner John F. Turner THE CONNECTICUT LIGHT AND 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 report to be signed on its behalf by the undersigned, thereunto duly authorized. THE CONNECTICUT LIGHT AND POWER COMPANY (Registrant) Date: June 10, 1998 By: /s/ Michael G. Morris Michael G. Morris Chairman Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. 7 Date Title Signature June 10, 1998 Chairman and /s/ Michael G. Morris a Director Michael G. Morris June 10, 1998 President and /s/ Hugh C. MacKenzie a Director Hugh C. MacKenzie June 10, 1998 Executive Vice /s/ John H. Forsgren President and John H. Forsgren Chief Financial Officer and a Director June 10, 1998 Vice President /s/ John J. Roman and Controller John J. Roman June 10, 1998 Director /s/ Bruce D. Kenyon Bruce D. Kenyon PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE (Registrant) Date: June 10, 1998 By: /s/ Michael G. Morris Michael G. Morris Chairman and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Date Title Signature June 10, 1998 Chairman and Chief /s/ Michael G. Morris Executive Officer Michael G. Morris and a Director June 10, 1998 President and /s/ William T. Frain, Jr. Chief Operating William T. Frain, Jr. Officer and a Director June 10, 1998 Executive Vice /s/ John H. Forsgren President and John H. Forsgren Chief Financial Officer and a Director June 10, 1998 Vice President /s/ John J. Roman and Controller John J. Roman PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SIGNATURES (CONT'D) Date Title Signature June 10, 1998 Director /s/ John C. Collins John C. Collins June 10, 1998 Director /s/ Bruce D. Kenyon Bruce D. Kenyon June 10, 1998 Director /s/ Gerald Letendre Gerald Letendre June 10, 1998 Director /s/ Hugh C. MacKenzie Hugh C. MacKenzie June 10, 1998 Director /s/ Jane E. Newman Jane E. Newman WESTERN 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 report to be signed on its behalf by the undersigned, thereunto duly authorized. WESTERN MASSACHUSETTS ELECTRIC COMPANY (Registrant) Date: June 10, 1998 By: /s/ Michael G. Morris Michael G. Morris Chairman Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Date Title Signature June 10, 1998 Chairman and /s/ Michael G. Morris a Director Michael G. Morris June 10, 1998 President and /s/ Hugh C. MacKenzie a Director Hugh C. MacKenzie June 10, 1998 Executive Vice /s/ John H. Forsgren President and John H. Forsgren Chief Financial Officer and a Director June 10, 1998 Vice President /s/ John J. Roman and Controller John J. Roman June 10, 1998 Director /s/ Bruce D. Kenyon Bruce D. Kenyon REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES We have audited in accordance with generally accepted auditing standards, the restated financial statements of Northeast Utilities, The Connecticut Light and Power Company and Western Massachusetts Electric Company incorporated by reference in this Form 10-K/A, and have issued our report thereon dated February 20, 1998 (except with respect to the matter discussed in Note 1, as to which the date is June 10, 1998). Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules, as restated - see Note 1, listed in the accompanying Index to Financial Statements Schedules are the responsibility of the companies' management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/ ARTHUR ANDERSEN LLP Hartford, Connecticut February 20, 1998 (except with respect to the matter discussed in Note 1, as to which the date is June 10, 1998) REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES We have audited in accordance with generally accepted auditing standards, the restated financial statements of Public Service Company of New Hampshire, incorporated by reference in this Form 10-K/A and have issued our report thereon dated February 20, 1998 (except with respect to the matter discussed in Note 1 as to which the date is June 10, 1998). Our report includes an explanatory paragraph regarding the existence of conditions which raise substantial doubt about the company's ability to continue as a going concern. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules, as restated - see Note 1, listed in the accompanying Index to Financial Statements Schedules are the responsibility of the company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/ ARTHUR ANDERSEN LLP Hartford, Connecticut February 20, 1998 (except with respect to the matter discussed in Note 1, as to which the date is June 10, 1998) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports included (or incorporated by reference) in this Form 10-K/A, into the Company's previously filed Registration Statements No. 33-55279 of The Connecticut Light and Power Company, No. 33-56537 of CL&P Capital, LP and No. 33-34622, No. 33-44814, No. 33-63023, No. 33-40156, No. 333-52413, and No. 333-52415 of Northeast Utilities. /s/ ARTHUR ANDERSEN LLP Hartford, Connecticut June 10, 1998 INDEX TO FINANCIAL STATMENTS SCHEDULES Schedule I. Amended Financial Information of Registrant: Northeast Utilities (Parent) Balance Sheets 1997 and 1996 S-5 Northeast Utilities (Parent) Statements of Income 1997, 1996, and 1995 S-6 Northeast Utilities (Parent) Statements of Cash Flows 1997, 1996, and 1995 S-7 II. Amended Valuation and Qualifying Accounts and Reserves 1997, 1996, and 1995: Northeast Utilities and Subsidiaries S-8 - S-10 The Connecticut Light and Power Company and Subsidiaries S-11 - S-13 Public Service Company of New Hampshire S-14 - S-16 Western Massachusetts Electric Company and Subsidiary S-17 - S-19 All other schedules of the companies' for which provision is made in the applicable regulations of the Securities and Exchange Commission are not required under the related instructions or are not applicable, and therefore have been omitted. SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT BALANCE SHEETS AT DECEMBER 31, 1997 AND 1996 (Thousands of Dollars)
1997 1996 (Restated) (Restated) ---------- ---------- ASSETS - ------ Other Property and Investments: Investments in subsidiary companies, at equity............................................... $2,314,746 $2,543,352 Investments in transmission companies, at equity...... 19,635 21,186 Other, at cost........................................ 402 413 ----------- ----------- 2,334,783 2,564,951 ----------- ----------- Current Assets: Cash.................................................. 10 10 Notes receivable from affiliated companies............ 34,200 5,475 Notes and accounts receivable......................... 711 813 Receivables from affiliated companies................. 961 7,106 Prepayments........................................... 265 224 ----------- ----------- 36,147 13,628 ----------- ----------- Deferred Charges: Accumulated deferred income taxes..................... 5,692 5,293 Unamortized debt expense.............................. 232 524 Other................................................. 47 46 ----------- ----------- 5,971 5,863 ----------- ----------- Total Assets..................................... $2,376,901 $2,584,442 =========== =========== CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common Shareholders' Equity: Common shares, $5 par value--Authorized 225,000,000 shares; 136,842,170 shares issued and 130,182,736 shares outstanding in 1997 and 136,051,938 shares issued and 128,444,373 outstanding in 1996..................... $ 684,211 $ 680,260 Capital surplus, paid in.............................. 932,493 940,446 Deferred contribution plan--employee stock ownership plan (ESOP)......................................... (154,141) (176,091) Retained earnings..................................... 707,522 869,618 ----------- ----------- Total common shareholders' equity................... 2,170,085 2,314,233 Long-term debt........................................ 177,000 194,000 ----------- ----------- Total capitalization................................ 2,347,085 2,508,233 ----------- ----------- Current Liabilities: Notes payable to banks................................ - 38,750 Long-term debt and preferred stock--current portion... 17,000 16,000 Accounts payable...................................... 1,857 15,504 Accounts payable to affiliated companies.............. 216 600 Accrued taxes......................................... 7,860 2,158 Accrued interest...................................... 2,343 2,602 Dividend reinvestment plan............................ 90 - Other................................................. - 2 ----------- ----------- 29,366 75,616 ----------- ----------- Other Deferred Credits.................................. 450 593 ----------- ----------- Total Capitalization and Liabilities $2,376,901 $2,584,442 =========== ===========
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF INCOME YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995 (Thousands of Dollars Except Share Information)
1997 1996 (Restated) (Restated) 1995 ------------- ------------- ------------- Operating Revenues.................. $ - $ - $ - ------------- ------------- ------------- Operating Expenses: Other............................. 8,657 8,920 14,267 Federal income taxes.............. (10,697) (10,390) (8,585) ------------- ------------- ------------- Total operating expenses......... (2,040) (1,470) 5,682 ------------- ------------- ------------- Operating Income (Loss)............. 2,040 1,470 (5,682) ------------- ------------- ------------- Other Income: Equity in earnings of subsidiaries..................... (118,195) 55,370 310,025 Equity in earnings of transmission companies........... 2,968 3,306 3,561 Other, net........................ 2,184 368 329 ------------- ------------- ------------- Other income, net............... (113,043) 59,044 313,915 ------------- ------------- ------------- (Loss) Income before interest charges.............. (111,003) 60,514 308,233 ------------- ------------- ------------- Interest Charges.................... 18,959 21,585 25,799 ------------- ------------- ------------- Net (Loss)/Income................... $ (129,962) $ 38,929 $ 282,434 ============= ============= ============= (Loss)/Earnings Per Common Share.... $ (1.01) $ 0.30 $ 2.24 ============= ============= ============= Common Shares Outstanding (average).......................... 129,567,708 127,960,382 126,083,645 ============= ============= =============
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENT OF CASH FLOWS YEARS ENDED DECEMBER 31, 1997, 1996, 1995 (Thousands of Dollars) 1997 1996
(Restated) (Restated) 1995 ------------ -------------- -------------- Operating Activities: Net (loss) income...................................... $ (129,962) $ 38,929 $ 282,434 Adjustments to reconcile to net cash from operating activities: Equity in earnings of subsidiary companies........... 118,195 (55,370) (310,025) Cash dividends received from subsidiary companies.... 132,994 247,101 272,350 Deferred income taxes................................ 1,558 3,868 772 Other sources of cash................................ 11,738 17,961 6,916 Other uses of cash................................... (2,101) (3,065) (528) Changes in working capital: Receivables........................................ 6,247 (7,312) 1,991 Accounts payable................................... (14,031) (3,183) 15,381 Other working capital (excludes cash).............. 5,490 (13,724) 7,396 ------------ -------------- -------------- Net cash flows from operating activities................. 130,128 225,205 276,687 ------------ -------------- -------------- Financing Activities: Issuance of common shares.............................. 6,502 10,622 47,218 Net decrease in short-term debt........................ (38,750) (18,750) (46,500) Reacquisitions and retirements of long-term debt....... (16,000) (14,000) (12,000) Cash dividends on common shares........................ (32,134) (176,276) (221,701) ------------ -------------- -------------- Net cash flows used for financing activities............. (80,382) (198,404) (232,983) ------------ -------------- -------------- Investment Activities: NU System Money Pool................................... (28,725) 4,200 (7,700) Investment in subsidiaries............................. (22,583) (33,217) (38,963) Other investment activities, net....................... 1,562 2,208 2,935 ------------ -------------- -------------- Net cash flows used for investments...................... (49,746) (26,809) (43,728) ------------ -------------- -------------- Net decrease in cash for the period...................... 0 (8) (24) Cash - beginning of period............................... 10 18 42 ------------ -------------- -------------- Cash - end of period..................................... $ 10 $ 10 $ 18 ============ ============== ============== Supplemental Cash Flow Information Cash paid during the year for: Interest, net of amounts capitalized................... $ 18,960 $ 21,770 $ 26,430 ============ ============== ============== Income taxes (refund).................................. $ (16,000) $ (7,700) $ (8,418) ============ ============== ==============
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated) YEAR ENDED DECEMBER 31, 1997 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged Balance at Charged to to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------ RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 17,062 $ 14,854 $ - $ 29,864 (a) $ 2,052 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 36,260 $ 9,542 $ - $ 11,365 (b) $ 34,437 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated) YEAR ENDED DECEMBER 31, 1996 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged Balance at Charged to to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 14,379 $ 21,761 $ - $ 19,078 (a) $ 17,062 ========= ========= ========= ========== ========== Asset valuation reserves $ 10,266 $ $ - $ 10,266 $ 0 ========= ========= ========= ========== ========== RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 38,409 $ 8,397 $ - $ 10,546 (b) $ 36,260 ========= ========= ========= ========== ========== (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1995 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged Balance at Charged to to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 16,826 $ 18,010 $ - $ 20,458 (a)$ 14,378 ========= ========= ========= ========= ========= Asset valuation reserves $ 8,684 $ 1,582 $ - $ - $ 10,266 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 34,721 $ 11,475 $ - $ 7,787 (b)$ 38,409 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated) YEAR ENDED DECEMBER 31, 1997 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged Balance at Charged to to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------ RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 13,241 $ 10,509 $ - $ 23,450 (a) $ 300 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 18,879 $ 4,458 $ - $ 8,375 (b) $ 14,962 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated) YEAR ENDED DECEMBER 31, 1996 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged Balance at Charged to to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 10,567 $ 15,704 $ - $ 13,030 (a) $ 13,241 ========= ========= ========= ========== ========== Asset valuation reserves $ 10,266 $ - $ - $ 10,266 $ 0 ========= ========= ========= ========== ========== RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 19,874 $ 5,709 $ - $ 6,704 (b) $ 18,879 ========= ========= ========= ========== ========== (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1995 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged Balance at Charged to to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 12,778 $ 12,722 $ - $ 14,933 (a)$ 10,567 ========= ========= ========= ========= ========= Asset valuation reserves $ 8,684 $ 1,582 $ - $ - $ 10,266 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 19,529 $ 5,633 $ - $ 5,288 (b)$ 19,874 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated) YEAR ENDED DECEMBER 31, 1997 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------ RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 1,700 $ 3,259 $ - $ 3,257 (a) $ 1,702 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 7,265 $ 1,647 $ - $ 1,124 (b) $ 7,788 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated) YEAR ENDED DECEMBER 31, 1996 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged Balance at Charged to to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 1,582 $ 2,906 $ - $ 2,788 (a) $ 1,700 ========= ========= ========= ========== ========== RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 8,142 1,040 $ - $ 1,917 (b) $ 7,265 ========= ========= ========= ========== ========== (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1995 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged Balance at Charged to to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 2,015 $ 2,454 $ - $ 2,887 (a)$ 1,582 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 5,113 $ 3,668 $ - $ 639 (b)$ 8,142 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated) YEAR ENDED DECEMBER 31, 1997 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged Balance at Charged to to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------ RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 2,121 $ 1,086 $ - $ 3,157 (a) $ 50 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 5,575 $ 1,093 $ - $ 1,165 (b) $ 5,503 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES (Restated) YEAR ENDED DECEMBER 31, 1996 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged Balance at Charged to to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 2,230 $ 3,097 $ - $ 3,206 (a) $ 2,121 ========= ========= ========= ========== ========== RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 5,144 $ 1,222 $ - $ 791 (b) $ 5,575 ========= ========= ========= ========== ========== (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1995 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged Balance at Charged to to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 2,032 $ 2,836 $ - $ 2,638 (a)$ 2,230 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 4,674 $ 1,340 $ - $ 870 (b)$ 5,144 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
EXHIBIT INDEX Each document described below is incorporated by reference to the files of the Securities and Exchange Commission, unless the reference to the document is marked as follows: & - Filed with the 1997 Annual Report on Form 10-K/A for NU and herein incorporated by reference from the 1997 NU Form 10-K/A, File No. 1-5324 into the 1997 Annual Report on Form 10-K/A for CL&P, PSNH and WMECO. * - Filed with the 1997 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1997 NU Form 10-K, File No. 1-5324 into the 1997 Annual Report on Form 10-K for CL&P, PSNH, WMECO and NAEC. # - Filed with the 1997 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1997 NU Form 10-K, File No. 1-5324 into the 1997 Annual Report on Form 10-K for CL&P. @ - Filed with the 1997 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1997 NU Form 10-K, File No. 1-5324 into the 1997 Annual Report on Form 10-K for PSNH. ** - Filed with the 1997 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1997 NU Form 10-K, File No. 1-5324 into the 1997 Annual Report on Form 10-K for WMECO. ## - Filed with the 1997 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1997 Form 10-K, File No. 1-5324 into the 1997 Annual Report on Form 10-K for NAEC. Exhibit Number Description 3 Articles of Incorporation and By-Laws 3.1 Northeast Utilities 3.1.1 Declaration of Trust of NU, as amended through May 24, 1988. (Exhibit 3.1.1, 1988 NU Form 10-K, File No. 1-5324) 3.2 The Connecticut Light and Power Company 3.2.1 Certificate of Incorporation of CL&P, restated to March 22, 1994. (Exhibit 3.2.1, 1993 NU Form 10-K, File No. 1-5324) 3.2.2 Certificate of Amendment to Certificate of Incorporation of CL&P, dated December 26, 1996. (Exhibit 3.2.2, 1996 NU Form 10-K, File No. 1-5324) 3.2.3 By-laws of CL&P, as amended to January 1, 1997. (Exhibit 3.2.3, 1996 NU Form 10-K, File No. 1-5324) 3.3 Public Service Company of New Hampshire 3.3.1 Articles of Incorporation, as amended to May 16, 1991. (Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324) 3.3.2 By-laws of PSNH, as amended to November 1, 1993. (Exhibit 3.3.2, 1993 NU Form 10-K, File No. 1-5324) 3.4 Western Massachusetts Electric Company 3.4.1 Articles of Organization of WMECO, restated to February 23, 1995. (Exhibit 3.4.1, 1994 NU Form 10-K, File No. 1-5324) ** 3.4.2 By-laws of WMECO, as amended to February 11, 1998. 3.5 North Atlantic Energy Corporation 3.5.1 Articles of Incorporation of NAEC dated September 20, 1991. (Exhibit 3.5.1, 1993 NU Form 10-K, File No. 1-5324) 3.5.2 Articles of Amendment dated October 16, 1991 and June 2, 1992 to Articles of Incorporation of NAEC. (Exhibit 3.5.2, 1993 NU Form 10-K, File No. 1-5324) 3.5.3 By-laws of NAEC, as amended to November 8, 1993. (Exhibit 3.5.3, 1993 NU Form 10-K, File No. 1-5324) 4 Instruments defining the rights of security holders, including indentures 4.1 Northeast Utilities 4.1.1 Indenture dated as of December 1, 1991 between Northeast Utilities and IBJ Schroder Bank & Trust Company, with respect to the issuance of Debt Securities. (Exhibit 4.1.1, 1991 NU Form 10-K, File No. 1-5324) 4.1.2 First Supplemental Indenture dated as of December 1, 1991 between Northeast Utilities and IBJ Schroder Bank & Trust Company, with respect to the issuance of Series A Notes. (Exhibit 4.1.2, 1991 NU Form 10-K, File No. 1-5324) 4.1.3 Second Supplemental Indenture dated as of March 1, 1992 between Northeast Utilities and IBJ Schroder Bank & Trust Company with respect to the issuance of 8.38% Amortizing Notes. (Exhibit 4.1.3, 1992 NU Form 10-K, File No. 1-5324) 4.1.4 Credit Agreements among CL&P, NU, WMECO, NUSCO (as Agent) and 3 Commercial Banks dated December 3, 1992 (Three-Year Facility). (Exhibit C.2.38, 1992 NU Form U5S, File No. 30-246) 4.1.5 Credit Agreements among CL&P, WMECO, NU, Holyoke Water Power Company, RRR, NNECO and NUSCO (as Agent) and 1 commercial bank dated December 3, 1992 (Three-Year Facility). (Exhibit C.2.39, 1992 NU Form U5S, File No. 30-246) 4.1.6 Credit Agreement among NU, CL&P and WMECO and several commercial banks, dated as of November 21, 1996. (Exhibit No. B.1, File No. 70-8875) 4.1.7 First Amendment and Waiver dated as of May 30, 1997 to Credit Agreement dated as of November 21, 1996 among NU, CL&P, WMECO, and the Co-Agents and Banks named therein. (Exhibit B.4(a) (Execution Copy), File No. 70-8875) 4.1.8 Credit Agreement dated as of February 10, 1998 among NU, the Lenders named therein, and Toronto Dominion (Texas), Inc., as Administrative Agent, TD Securities (USA) Inc., as Arranger. (Exhibit B.9 (Execution Copy), File No. 70-8875) 4.2 The Connecticut Light and Power Company 4.2.1 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921. (Composite including all twenty-four amendments to May 1, 1967.) (Exhibit 4.1.1, 1989 NU Form 10-K, File No. 1-5324) Supplemental Indentures to the Composite May 1, 1921 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, dated as of: 4.2.2 December 1, 1969. (Exhibit 4.20, File No. 2-60806) 4.2.3 June 30, 1982. (Exhibit 4.33, File No. 2-79235) 4.2.4 December 1, 1989. (Exhibit 4.1.26, 1989 NU Form 10-K, File No. 1-5324) 4.2.5 July 1, 1992. (Exhibit 4.31, File No. 33-59430) 4.2.6 July 1, 1993. (Exhibit A.10(b), File No. 70-8249) 4.2.7 July 1, 1993. (Exhibit A.10(b), File No. 70-8249) 4.2.8 December 1, 1993. (Exhibit 4.2.14, 1993 NU Form 10-K, File No. 1-5324) 4.2.9 February 1, 1994. (Exhibit 4.2.15, 1993 NU Form 10-K, File No. 1-5324) 4.2.10 February 1, 1994. (Exhibit 4.2.16, 1993 NU Form 10-K, File No. 1-5324) 4.2.11 June 1, 1994. (Exhibit 4.2.15, 1994 NU Form 10-K, File No. 1-5324) 4.2.12 October 1, 1994. (Exhibit 4.2.16, 1994 NU Form 10-K, File No. 1-5324) 4.2.13 June 1, 1996. (Exhibit 4.2.16, 1996 NU Form 10-K, File No. 1-5324) 4.2.14 January 1, 1997. (Exhibit 4.2.17, 1996 NU Form 10-K, File No. 1-5324 4.2.15 May 1, 1997. (Exhibit 4.19, File No. 333-30911) 4.2.16 June 1, 1997. (Exhibit 4.20, File No. 333-30911) # 4.2.17 June 1, 1997. 4.2.18 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1986 Series) dated as of December 1, 1986. (Exhibit C.1.47, 1986 NU Form U5S, File No. 30-246) 4.2.18.1 Letter of Credit and Reimbursement Agreement (Pollution Control Bonds, 1986 Series) dated as of August 1, 1994. (Exhibit 1 (Execution Copy), File No. 70-7320) 4.2.19 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1988 Series) dated as of October 1, 1988. (Exhibit C.1.55, 1988 NU Form U5S, File No. 30-246) 4.2.19.1 Letter of Credit (Pollution Control Bonds, 1988 Series) dated October 27, 1988. (Exhibit 4.2.17.1, 1995 NU Form 10-K, File No. 1-5324) 4.2.19.2 Reimbursement and Security Agreement (Pollution Control Bonds, 1988 Series) dated as of October 1, 1988. (Exhibit 4.2.17.2, 1995 NU Form 10-K, File No. 1-5324) 4.2.20 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds) dated as of December 1, 1989. (Exhibit C.1.39, 1989 NU Form U5S, File No. 30-246) 4.2.21 Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire, CL&P and the Trustee (Pollution Control Bonds, 1992 Series A) dated as of December 1, 1992.(Exhibit C.2.33, 1992 NU Form U5S, File No. 30-246) 4.2.21.1 Letter of Credit and Reimbursement Agreement (Pollution Control Bonds, 1992 Series A) dated as of December 1, 1992. (Exhibit 4.2.19.1, 1995 NU Form 10-K, File No. 1-5324) 4.2.22 Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.21, 1993 NU Form 10-K, File No. 1-5324) 4.2.22.1 Letter of Credit and Reimbursement Agreement (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.23, 1993 NU Form 10-K, File No. 1-5324) 4.2.23 Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series B, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.22, 1993 NU Form 10-K, File No. 1-5324) 4.2.23.1 Letter of Credit and Reimbursement Agreement (Pollution Control Bonds - Series B, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.24, 1993 NU Form 10-K, File No. 1-5324) 4.2.24 Amended and Restated Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Bond - 1996A Series) dated as of May 1, 1996 and Amended and Restated as of January 1, 1997. (Exhibit 4.2.24, 1996 NU Form 10-K, File No. 1-5324) 4.2.24.1 Amended and Restated Indenture of Trust between Connecticut Development Authority and the Trustee (CL&P Pollution Control Revenue Bond-1996A Series), dated as of May 1, 1996 and Amended and Restated as of January 1, 1997. (Exhibit 4.2.24.1, 1996 NU Form 10-K, File No. 1-5324) 4.2.24.2 Standby Bond Purchase Agreement among CL&P, Societe Generale, New York Branch and the Trustee, dated January 23, 1997. (Exhibit 4.2.24.2, 1996 NU Form 10-K, File No. 1-5324) # 4.2.24.3 Amendment No. 1, dated January 21, 1998, to the Standby Bond Purchase Agreement, dated January 23, 1997. 4.2.24.4 AMBAC Municipal Bond Insurance Policy issued by the Connecticut Development Authority (CL&P Pollution Control Revenue Bond-1996A Series), effective January 23, 1997. (Exhibit 4.2.24.3, 1996 NU Form 10-K, File No. 1-5324) 4.2.25 Amended and Restated Limited Partnership Agreement (CL&P Capital, L.P.) among CL&P, NUSCO, and the persons who became limited partners of CL&P Capital, L.P. in accordance with the provisions thereof dated as of January 23, 1995 (MIPS). (Exhibit A.1 (Execution Copy), File No. 70-8451) 4.2.26 Indenture between CL&P and Bankers Trust Company, Trustee (Series A Subordinated Debentures), dated as of January 1, 1995 (MIPS). (Exhibit B.1 (Execution Copy), File No. 70-8451) 4.2.27 Payment and Guaranty Agreement of CL&P dated as of January 23, 1995 (MIPS). (Exhibit B.3 (Execution Copy), File No. 70-8451) 4.3 Public Service Company of New Hampshire 4.3.1 First Mortgage Indenture dated as of August 15, 1978 between PSNH and First Fidelity Bank, National Association, New Jersey, Trustee, (Composite including all amendments to May 16, 1991). (Exhibit 4.4.1, 1992 NU Form 10-K, File No. 1-5324) 4.3.1.1 Tenth Supplemental Indenture dated as of May 1, 1991 between PSNH and First Fidelity Bank, National Association. (Exhibit 4.1, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392). 4.3.2 Revolving Credit Agreement, dated as of May 1, 1991 (includes a collateral mortgage). (Exhibit 4.12, PSNH Current Report on Form 8-K, File No. 1-6392) 4.3.2.1 Amended and Restated Revolving Credit Agreement, dated as of April 1, 1996 (includes amendment to collateral mortgage). (Exhibit 4.3.2, 1996 NU Form 10-K, File No. 1-5324) 4.3.3 Series A (Tax Exempt New Issue) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.2, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.4 Series B (Tax Exempt Refunding) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.3, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.5 Series C (Tax Exempt Refunding) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.4, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.6 Series D (Taxable New Issue) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.5, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.6.1 First Supplement to Series D (Tax Exempt Refunding Issue) PCRB Loan and Trust Agreement dated as of December 1, 1992. (Exhibit 4.4.5.1, 1992 NU Form 10-K, File No. 1-5324) 4.3.6.2 Second Series D (May 1, 1991 Taxable New Issue and December 1, 1992 Tax Exempt Refunding Issue) PCRB Letter of Credit and Reimbursement Agreement dated as of May 1, 1995 (Exhibit B.4, Execution Copy, File No. 70-8036) 4.3.7 Series E (Taxable New Issue) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.6, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.7.1 First Supplement to Series E (Tax Exempt Refunding Issue) PCRB Loan and Trust Agreement dated as of December 1, 1993. (Exhibit 4.3.8.1, 1993 NU Form 10-K, File No. 1-5324) 4.3.7.2 Second Series E (May 1, 1991 Taxable New Issue and December 1, 1993 Tax Exempt Refunding Issue) PCRB Letter of Credit and Reimbursement Agreement dated as of May 1, 1995. (Exhibit B.5, (Execution Copy), File No. 70-8036) 4.4 Western Massachusetts Electric Company 4.4.1 First Mortgage Indenture and Deed of Trust between WMECO and Old Colony Trust Company, Trustee, dated as of August 1, 1954. (Exhibit 4.4.1, 1993 NU Form 10-K, File No. 1-5324) Supplemental Indentures thereto dated as of: 4.4.2 October 1, 1954.(Exhibit 4.2, File No. 33-51185) ** 4.4.3 March 1, 1967. 4.4.4 July 1, 1973. (Exhibit 2.10. File No. 2-68808) 4.4.5 December 1, 1992. (Exhibit 4.15, File No. 33-55772) 4.4.6 January 1, 1993. (Exhibit 4.5.13, 1992 NU Form 10-K, File No. 1-5324) 4.4.7 March 1, 1994. (Exhibit 4.4.11, 1993 NU Form 10-K, File No. 1-5324) 4.4.8 March 1, 1994. (Exhibit 4.4.12, 1993 NU Form 10-K, File No. 1-5324) 4.4.9 May 1, 1997. (Exhibit 4.11, File No. 33-51185) ** 4.4.10 July 1, 1997. 4.4.11 Loan Agreement between Connecticut Development Authority and WMECO, (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.4.13, 1993 NU Form 10-K, File No. 1-5324) 4.4.11.1 Letter of Credit and Reimbursement Agreement (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.4.14, 1993 NU Form 10-K, File No. 1-5324) 4.5 North Atlantic Energy Corporation 4.5.1 First Mortgage Indenture and Deed of Trust between NAEC and United States Trust Company of New York, Trustee, dated as of June 1, 1992. (Exhibit 4.6.1, 1992 NU Form 10-K, File No. 1-5324) 4.5.2 Term Credit Agreement dated as of November 9, 1995. (Exhibit 4.5.2, 1995 NU Form 10-K, File No. 1-5324) 10 Material Contracts 10.1 Stockholder Agreement dated as of July 1, 1964 among the stockholders of Connecticut Yankee Atomic Power Company (CYAPC). (Exhibit 10.1, 1994 NU Form 10-K, File No. 1-5324) 10.2 Form of Power Contract dated as of July 1, 1964 between CYAPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.2, 1994 NU Form 10-K, File No. 1-5324) 10.2.1 Form of Additional Power Contract dated as of April 30, 1984, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324) 10.2.2 Form of 1987 Supplementary Power Contract dated as of April 1, 1987, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.6, 1987 NU Form 10-K, File No. 1-5324) 10.3 Capital Funds Agreement dated as of September 1, 1964 between CYAPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.3, 1994 NU Form 10-K, File No. 1-5324) 10.4 Stockholder Agreement dated December 10, 1958 between Yankee Atomic Electric Company (YAEC) and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.4, 1993 NU Form 10-K, File No. 1-5324) 10.5 Form of Amendment No. 3, dated as of April 1, 1985, to Power Contract between YAEC and each of CL&P, PSNH and WMECO, including a composite restatement of original Power Contract dated June 30, 1959 and Amendment No. 1 dated April 1, 1975 and Amendment No. 2 dated October 1, 1980. (Exhibit 10.5, 1988 NU Form 10-K, File No. 1-5324.) 10.5.1 Form of Amendment No. 4 to Power Contract, dated May 6, 1988, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324) 10.5.2 Form of Amendment No. 5 to Power Contract, dated June 26, 1989, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324) 10.5.3 Form of Amendment No. 6 to Power Contract, dated July 1,1989, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324) 10.5.4 Form of Amendment No. 7 to Power Contract, dated February 1, 1992, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.4, 1993 NU Form 10-K, File No. 1-5324) 10.6 Stockholder Agreement dated as of May 20, 1968 among stockholders of MYAPC. 10.7 Form of Power Contract dated as of May 20, 1968 between MYAPC and each of CL&P, HELCO, PSNH and WMECO. 10.7.1 Form of Amendment No. 1 to Power Contract dated as of March 1, 1983 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.1, 1993 NU Form 10-K, File No. 1-5324) 10.7.2 Form of Amendment No. 2 to Power Contract dated as of January 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.2, 1993 NU Form 10-K, File No. 1-5324) 10.7.3 Form of Amendment No. 3 to Power Contract dated as of October 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.7.3, 1994 NU Form 10-K, File No. 1-5324) 10.7.4 Form of Additional Power Contract dated as of February 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324) 10.8 Capital Funds Agreement dated as of May 20, 1968 between MYAPC and CL&P, PSNH, HELCO and WMECO. 10.8.1 Amendment No. 1 to Capital Funds Agreement, dated as of August 1, 1985, between MYAPC, CL&P, PSNH and WMECO. (Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324) 10.9 Sponsor Agreement dated as of August 1, 1968 among the sponsors of Vermont Yankee Nuclear Power Corporation (VYNPC). 10.10 Form of Power Contract dated as of February 1, 1968 between VYNPC and each of CL&P, HELCO, PSNH and WMECO. 10.10.1 Form of Amendment to Power Contract dated as of June 1, 1972 between VYNPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 5.22, File No. 2-47038) 10.10.2 Form of Second Amendment to Power Contract dated as of April 15, 1983 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.2, 1993 NU Form 10-K, File No. 1-5324) 10.10.3 Form of Third Amendment to Power Contract dated as of April 24, 1985 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.10.3, 1994 NU Form 10-K, File No. 1-5324) 10.10.4 Form of Fourth Amendment to Power Contract dated as of June 1, 1985 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.10.4, 1996 NU Form 10-K, File No. 1-5324) 10.10.5 Form of Fifth Amendment to Power Contract dated as of May 6, 1988 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.5, 1990 NU Form 10-K, File No. 1-5324) 10.10.6 Form of Sixth Amendment to Power Contract dated as of May 6, 1988 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.6, 1990 NU Form 10-K, File No. 1-5324) 10.10.7 Form of Seventh Amendment to Power Contract dated as of June 15, 1989 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.7, 1990 NU Form 10-K, File No. 1-5324) 10.10.8 Form of Eighth Amendment to Power Contract dated as of December 1, 1989 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.8, 1990 NU Form 10-K, File No. 1-5324) 10.10.9 Form of Additional Power Contract dated as of February 1, 1984 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.9, 1993 NU Form 10-K, File No. 1-5324) #@**10.11 Capital Funds Agreement dated as of February 1, 1968 between VYNPC and CL&P, HELCO, PSNH and WMECO. #@**10.11.1 Form of First Amendment to Capital Funds Agreement dated as of March 12, 1968 between VYNPC and CL&P, HELCO, PSNH and WMECO. 10.11.2 Form of Second Amendment to Capital Funds Agreement dated as of September 1, 1993 between VYNPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.11.2, 1993 NU Form 10-K, File No. 1-5324) 10.12 Amended and Restated Millstone Plant Agreement dated as of December 1, 1984 by and among CL&P, WMECO and Northeast Nuclear Energy Company (NNECO). (Exhibit 10.12, 1994 NU Form 10-K, File No. 1-5324) 10.13 Sharing Agreement dated as of September 1, 1973 with respect to 1979 Connecticut nuclear generating unit (Millstone 3). (Exhibit 6.43, File No. 2-50142) 10.13.1 Amendment dated August 1, 1974 to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 5.45, File No. 2-52392) 10.13.2 Amendment dated December 15, 1975 to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 7.47, File No. 2-60806) 10.13.3 Amendment dated April 1, 1986 to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 10.17.3, 1990 NU Form 10-K, File No. 1-5324) 10.14 Agreement dated July 19, 1990, among NAESCO and Seabrook Joint owners with respect to operation of Seabrook. (Exhibit 10.53, 1990 NU Form 10-K, File No. 1-5324) 10.15 Sharing Agreement between CL&P, WMECO, HP&E, HWP and PSNH dated as of June 1, 1992. (Exhibit 10.17, 1992 NU Form 10-K, File No. 1-5324) 10.16 Rate Agreement by and between NUSCO, on behalf of NU, and the Governor of the State of New Hampshire and the New Hampshire Attorney General dated as of November 22, 1989. (Exhibit 10.44, 1989 NU Form 10-K, File No. 1-5324) 10.16.1 First Amendment to Rate Agreement dated as of December 5, 1989. (Exhibit 10.16.1, 1995 NU Form 10-K, File No. 1-5324) 10.16.2 Second Amendment to Rate Agreement dated as of December 12, 1989. (Exhibit 10.16.2, 1995 NU Form 10-K, File No. 1-5324) 10.16.3 Third Amendment to Rate Agreement dated as of December 3, 1993. (Exhibit 10.16.3, 1995 NU Form 10-K, File No. 1-5324) 10.16.4 Fourth Amendment to Rate Agreement dated as of September 21, 1994. (Exhibit 10.16.4, 1995 NU Form 10-K, File No. 1-5324) 10.16.5 Fifth Amendment to Rate Agreement dated as of September 9, 1994. (Exhibit 10.16.5, 1995 NU Form 10-K, File No. 1-5324) 10.17 Form of Seabrook Power Contract between PSNH and NAEC, as amended and restated. (Exhibit 10.45, NU 1992 Form 10-K, File No. 1-5324) 10.18 Agreement (composite) for joint ownership, construction and operation of New Hampshire nuclear unit, as amended through the November 1, 1990 twenty-third amendment. (Exhibit No. 10.17, 1994 NU Form 10-K, File No. 1-5324) 10.18.1 Memorandum of Understanding dated November 7, 1988 between PSNH and Massachusetts Municipal Wholesale Electric Company (Exhibit 10.17, PSNH 1989 Form 10-K, File No. 1-6392) 10.18.2 Agreement of Settlement among Joint Owners dated as of January 13, 1989. (Exhibit 10.13.21, 1988 NU Form 10-K, File No. 1-5324) 10.18.2.1 Supplement to Settlement Agreement, dated as of February 7, 1989, between PSNH and Central Maine Power Company. (Exhibit 10.18.1, PSNH 1989 Form 10-K, File No. 1-6392) 10.19 Amended and Restated Agreement for Seabrook Project Disbursing Agent dated as of November 1, 1990. (Exhibit 10.4.7, File No. 33-35312) 10.19.1 Form of First Amendment to Exhibit 10.19. (Exhibit 10.4.8, File No. 33-35312) 10.19.2 Form (Composite) of Second Amendment to Exhibit 10.19. (Exhibit 10.18.2, 1993 NU Form 10-K, File No. 1-5324) 10.20 Agreement dated November 1, 1974 for Joint Ownership, Construction and Operation of William F. Wyman Unit No. 4 among PSNH, Central Maine Power Company and other utilities. (Exhibit 5.16 , File No. 2-52900) 10.20.1 Amendment to Exhibit 10.20 dated June 30, 1975. (Exhibit 5.48, File No. 2-55458) 10.20.2 Amendment to Exhibit 10.20 dated as of August 16, 1976. (Exhibit 5.19, File No. 2-58251) 10.20.3 Amendment to Exhibit 10.20 dated as of December 31, 1978. (Exhibit 5.10.3, File No. 2-64294) 10.21 Form of Service Contract dated as of July 1, 1966 between each of NU, CL&P and WMECO and the Service Company. (Exhibit 10.20, 1993 NU Form 10-K, File No. 1-5324) 10.21.1 Service Contract dated as of June 5, 1992 between PSNH and the Service Company. (Exhibit 10.12.4, 1992 NU Form 10-K, File No. 1-5324) 10.21.2 Service Contract dated as of June 5, 1992 between NAEC and the Service Company. (Exhibit 10.12.5, 1992 NU Form 10-K, File No. 1-5324) 10.21.3 Form of Service Agreement dated as of June 29, 1992 between PSNH and North Atlantic Energy Service Corporation, and the First Amendment thereto. (Exhibits B.7 and B.7.1, File No. 70-7787) 10.21.4 Form of Annual Renewal of Service Contract. (Exhibit 10.20.3, 1993 NU Form 10-K, File No. 1-5324) 10.22 Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of June 1, 1970 with respect to pooling of generation and transmission. (Exhibit 13.32, File No. 2-38177) 10.22.1 Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of February 2, 1982 with respect to pooling of generation and transmission. (Exhibit 10.21.1, 1993 NU Form 10-K, File No. 1-5324) 10.22.2 Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of January 1, 1984 with generation and transmission. (Exhibit 10.21.2, 1994 NU Form 10-K, File No. 1-5324) 10.23 New England Power Pool Agreement effective as of November 1, 1971, as amended to December 1, 1996. (Exhibit 10.15, 1988 NU Form 10-K, File No. 1-5324.) 10.23.1 Twenty-sixth Amendment to Exhibit 10.23 dated as of March 15, 1989. (Exhibit 10.15.1, 1990 NU Form 10-K, File No. 1-5324) 10.23.2 Twenty-seventh Amendment to Exhibit 10.23 dated as of October 1, 1990. (Exhibit 10.15.2, 1991 NU Form 10-K, File No. 1-5324) 10.23.3 Twenty-eighth Amendment to Exhibit 10.23 dated as of September 15, 1992. (Exhibit 10.18.3, 1992 NU Form 10-K, File No. 1-5324) 10.23.4 Twenty-ninth Amendment to Exhibit 10.23 dated as of May 1, 1993. (Exhibit 10.22.4, 1993 NU Form 10-K, File No. 1-5324) 10.23.5 Thirty-second Amendment (Amendments 30 and 31 were withdrawn) to Exhibit 10.23 dated as of September 1, 1995. (Exhibit 10.23.5, 1995 NU Form 10-K, File No. 1-5324) 10.23.6 Thirty-third Amendment to Exhibit 10.23 dated as of December 31, 1996 and Form of Interim Independent System Operator (ISO) Agreement. (Exhibit 10.23.6, 1996 NU Form 10-K, File No. 1-5324) 10.24 Agreements among New England Utilities with respect to the Hydro-Quebec interconnection projects. (See Exhibits 10(u) and 10(v); 10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K of New England Electric System, File No. 1-3446.) 10.25 Trust Agreement dated February 11, 1992, between State Street Bank and Trust Company of Connecticut, as Trustor, and Bankers Trust Company, as Trustee, and CL&P and WMECO, with respect to NBFT. (Exhibit 10.23, 1991 NU Form 10-K, File No. 1-5324) 10.25.1 Nuclear Fuel Lease Agreement dated as of February 11, 1992, between Bankers Trust Company, Trustee, as Lessor, and CL&P and WMECO, as Lessees. (Exhibit 10.23.1, 1991 NU Form 10-K, File No. 1-5324) 10.26 Simulator Financing Lease Agreement, dated as of February 1, 1985, by and between ComPlan and NNECO. (Exhibit 10.25, 1994 NU Form 10-K, File No. 1-5324) 10.27 Simulator Financing Lease Agreement, dated as of May 2, 1985, by and between The Prudential Insurance Company of America and NNECO. (Exhibit No. 10.26, 1994 NU Form 10-K, File No. 1-5324) 10.28 Lease dated as of April 14, 1992 between The Rocky River Realty Company (RRR) and Northeast Utilities Service Company (NUSCO) with respect to the Berlin, Connecticut headquarters (office lease). (Exhibit 10.29, 1992 NU Form 10-K, File No. 1-5324) 10.28.1 Lease dated as of April 14, 1992 between RRR and NUSCO with respect to the Berlin, Connecticut headquarters (project lease). (Exhibit 10.29.1, 1992 NU Form 10-K, File No. 1-5324) 10.29 Millstone Technical Building Note Agreement dated as of December 21, 1993 between, by and between The Prudential Insurance Company of America and NNECO. (Exhibit 10.28, 1993 NU Form 10-K, File No. 1-5324) 10.30 Lease and Agreement, dated as of December 15, 1988, by and between WMECO and Bank of New England, N.A., with BNE Realty Leasing Corporation of North Carolina. (Exhibit 10.63, 1988 NU Form 10-K, File No. 1-5324.) 10.31 Note Agreement dated April 14, 1992, by and between The Rocky River Realty Company (RRR) and Purchasers named therein (Connecticut General Life Insurance Company, Life Insurance Company of North America, INA Life Insurance Company of New York, Life Insurance Company of Georgia), with respect to RRR's sale of $15 million of guaranteed senior secured notes due 2007 and $28 million of guaranteed senior secured notes due 2017. (Exhibit 10.52, 1992 NU Form 10-K, File No. 1-5324) * 10.31.1 Amendment to Note Agreement, dated September 26, 1997. 10.31.2 Note Guaranty dated April 14, 1992 by Northeast Utilities pursuant to Note Agreement dated April 14, 1992 between RRR and Note Purchasers, for the benefit of The Connecticut National Bank as Trustee, the Purchasers and the owners of the notes. (Exhibit 10.52.1, 1992 NU Form 10-K, File No. 1-5324) * 10.31.2.1 Extension of Note Guaranty, dated September 26, 1997. 10.31.3 Assignment of Leases, Rents and Profits, Security Agreement and Negative Pledge, dated as of April 14, 1992 among RRR, NUSCO and The Connecticut National Bank as Trustee, securing notes sold by RRR pursuant to April 14, 1992 Note Agreement. (Exhibit 10.52.2, 1992 NU Form 10-K, File No. 1-5324) * 10.31.3.1 Modification of and Confirmation of Assignment of Leases, Rents and Profits, Security Agreement and Negative Pledge, dated as of September 26, 1997. * 10.31.4 Purchase and Sale Agreement, dated July 28, 1997 by and between RRR and the Sellers and Purchasers named therein. * 10.31.5 Purchase and Sale Agreement, dated September 26, 1997 by and between RRR and the Purchaser named therein. 10.32 Master Trust Agreement dated as of September 2, 1986 between CL&P and WMECO and Colonial Bank as Trustee, with respect to reserve funds for Millstone 1 decommissioning costs. (Exhibit No. 10.32, 1996 NU Form 10-K, File No. 1-5324) 10.32.1 Notice of Appointment of Mellon Bank, N.A. as Successor Trustee, dated November 20, 1990, and Acceptance of Appointment. (Exhibit 10.41.1, 1992 NU Form 10-K, File No. 1-5324) 10.33 Master Trust Agreement dated as of September 2, 1986 between CL&P and WMECO and Colonial Bank as Trustee, with respect to reserve funds for Millstone 2 decommissioning costs. (Exhibit No. 10.33, 1996 NU Form 10-K, File No. 1-5324) 10.33.1 Notice of Appointment of Mellon Bank, N.A. as Successor Trustee, dated November 20, 1990, and Acceptance of Appointment. (Exhibit 10.42.1, 1992 NU Form 10-K, File No. 1-5324) 10.34 Master Trust Agreement dated as of April 23, 1986 between CL&P and WMECO and Colonial Bank as Trustee, with respect to reserve funds for Millstone 3 decommissioning costs. (Exhibit No. 10.34, 1996 NU Form 10-K, File No. 1-5324) 10.34.1 Notice of Appointment of Mellon Bank, N.A. as Successor Trustee, dated November 20, 1990, and Acceptance of Appointment. (Exhibit 10.43.1, 1992 NU Form 10-K, File No. 1-5324) 10.35 NU Executive Incentive Plan, effective as of January 1, 1991. (Exhibit 10.44, NU 1991 Form 10-K, File No. 1-5324) 10.36 Supplemental Executive Retirement Plan for Officers of NU System Companies, Amended and Restated effective as of January 1, 1992. (Exhibit 10.45.1, NU Form 10-Q for the Quarter Ended June 30, 1992, File No. 1-5324) 10.36.1 Amendment 1 to Exhibit 10.36, effective as of August 1, 1993. (Exhibit 10.35.1, 1993 NU Form 10-K, File No. 1-5324) 10.36.2 Amendment 2 to Exhibit 10.36, effective as of January 1, 1994. (Exhibit 10.35.2, 1993 NU Form 10-K, File No. 1-5324) 10.36.3 Amendment 3 to Exhibit 10.36, effective as of January 1, 1996. (Exhibit 10.36.3, 1995 NU Form 10-K, File No. 1-5324) 10.37 Special Severance Program for Officers of NU System Companies, as adopted on June 9, 1997. (Exhibit No. 10.33, File No. 333-30911) 10.38 Loan Agreement dated as of December 2, 1991, by and between NU and Mellon Bank, N.A., as Trustee, with respect to NU's loan of $175 million to an ESOP Trust. (Exhibit 10.46, NU 1991 Form 10-K, File No. 1-5324) 10.38.1 First Amendment to Exhibit 10.37 dated February 7, 1992. (Exhibit 10.36.1, 1993 NU Form 10-K, File No. 1-5324) 10.38.2 Loan Agreement dated as of March 19, 1992 by and between NU and Mellon Bank, N.A., as Trustee, with respect to NU's loan of $75 million to the ESOP Trust. (Exhibit 10.49.1, 1992 NU Form 10-K, File No. 1-5324) 10.38.3 Second Amendment to Exhibit 10.37 dated April 9, 1992. (Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324) * 10.39 Employment Agreement with Michael G. Morris. 10.40 Transition and Retirement Agreement with Bernard M. Fox. (Exhibit 10.39, 1996 NU Form 10-K, File No. 1-5324) 10.41 Employment Agreement with Bruce M. Kenyon. (Exhibit 10.40, 1996 NU Form 10-K, File No. 1-5324) 10.42 Employment Agreement with John H. Forsgren. (Exhibit 10.41, 1996 NU Form 10-K, File No. 1-5324) 10.43 Employment Agreement with Hugh C. MacKenzie. (Exhibit 10.42, 1996 NU Form 10-K, File No. 1-5324) * 10.44 Employment Agreement with Robert P. Wax. 10.45 Northeast Utilities Deferred Compensation Plan for Trustees, Amended and Restated December 13, 1994. (Exhibit 10.39, 1995 NU Form 10-K, File No. 1-5324) 10.46 Deferred Compensation Plan for Officers of Northeast Utilities System Companies adopted September 23, 1986. (Exhibit 10.40, 1995 NU Form 10-K, File No. 1-5324) 10.47 Northeast Utilities Deferred Compensation Plan for Executives, adopted January 13, 1998. (Exhibit A.5, File No. 70-09185) 10.48 Reciprocal Support Agreement Among NNECO, NAESCO, CYAPC, YAEC and NUSCO dated January 1, 1996. (Exhibit 10.41, 1995 NU Form 10K, File No. 1-5324) # 10.49 Receivables Purchase and Sale Agreement (CL&P and CL&P Receivables Corporation), dated as of September 30, 1997. # 10.49.1 Purchase and Contribution Agreement (CL&P and CL&P Receivables Corporation), dated as of September 30, 1997. ** 10.50 Receivables Purchase Agreement (WMECO and WMECO Receivables Corporation), dated as of May 22, 1997. ** 10.50.1 Purchase and Sale Agreement (WMECO and WMECO Receivables Corporation), dated as of May 22, 1997. 10.51 Master Lease Agreement between General Electric Capital Corporation and CL&P, dated as of June 21, 1996. (Exhibit 10.50, 1996 NU Form 10-K, File No. 1-5324) # 10.51.1 Amendment No. 1 to Master Lease Agreement, dated as of August 29, 1997. 13 Annual Report to Security Holders (Each of the Annual Reports is filed only with the Form 10-K/A of that respective registrant.) & 13.1 Amended Annual Report to Shareholders of NU. & 13.2 Amended Annual Report of CL&P. & 13.3 Amended Annual Report of WMECO. & 13.4 Amended Annual Report of PSNH. *21 Subsidiaries of the Registrant. 27 Amended Financial Data Schedules (Each Financial Data Schedule is filed only with the Form 10-K/A of that respective registrant.) & 27.1 Amended Financial Data Schedule of NU. & 27.2 Amended Financial Data Schedule of CL&P. & 27.3 Amended Financial Data Schedule of WMECO. & 27.4 Amended Financial Data Schedule of PSNH. EX-13.1 2 ANNUAL REPORT OF NU EXHIBIT 13.1 EXHIBIT 13.1 NORTHEAST UTILITIES AND SUBSIDIARIES AMENDED 1997 ANNUAL REPORT TO SHAREHOLDERS Northeast Utilities and Subsidiaries Amended 1997 Annual Report Index Contents Page Company Report....................................................... 2 Report of Independent Public Accountants............................. 3 Consolidated Balance Sheets (Restated)............................... 4-5 Consolidated Statements of Income (Restated)......................... 6 Consolidated Statements of Cash Flows (Restated)..................... 7 Consolidated Statements of Shareholders' Equity (Restated)........... 8 Consolidated Statements of Capitalization (Restated)................. 9 Notes to Consolidated Statements of Capitalization................... 10 Consolidated Statements of Income Taxes (Restated)................... 12 Notes to Consolidated Financial Statements (Restated)................ 13 Management's Discussion and Analysis of Financial Condition and Results of Operations (Restated)....................... 48 Statement of Quarterly Financial Data (Restated)..................... 64 Consolidated Generation Statistics................................... 64 Selected Consolidated Financial Data (Restated)...................... 65 Consolidated Sales Statistics........................................ 66 Company Report The consolidated financial statements of Northeast Utilities and subsidiaries and other sections of this Annual Report were prepared by the company. These financial statements, which were audited by Arthur Andersen LLP, were prepared in accordance with generally accepted accounting principles using estimates and judgment, where required, and giving consideration to materiality. The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities. The company maintains a system of internal controls over financial reporting which is designed to provide reasonable assurance to the company's management and Board of Trustees regarding the preparation of reliable, published financial statements. The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits. Through established programs, the company regularly communicates to its management employees their internal control responsibilities and policies prohibiting conflict of interest. The Audit Committee of the Board of Trustees is composed entirely of outside trustees. This committee meets periodically with management, the internal auditors and the independent auditors to review the activities of each and to discuss audit matters, financial reporting and the adequacy of internal controls. Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected. The company believes, however, that its system of internal accounting controls and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable. Report of Independent Public Accountants To the Board of Trustees and Shareholders of Northeast Utilities: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization, as restated - see Note 1, of Northeast Utilities (a Massachusetts trust) and subsidiaries as of December 31, 1997 and 1996, and the related consolidated statements of income, common shareholders' equity, cash flows and income taxes, as restated - see Note 1, for each of the three years in the period ended December 31, 1997. 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 Northeast Utilities and subsidiaries as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. As explained in Note 1 to the consolidated financial statements, the company has given retroactive effect to the change in accounting for nuclear compliance costs. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 20, 1998 (except with respect to the matter discussed in Note 1, as to which the date is June 10, 1998) NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Balance Sheets
- ---------------------------------------------------------------------------------------- At December 31, - ---------------------------------------------------------------------------------------- (Thousands of Dollars) 1997 1996 (Restated) (Restated) - ---------------------------------------------------------------------------------------- Assets - ------ Utility Plant, at cost: Electric................................................... $ 9,869,561 $ 9,685,155 Other...................................................... 186,130 192,303 ------------ ------------ 10,055,691 9,877,458 Less: Accumulated provision for depreciation............ 4,330,599 3,979,864 ------------ ------------ 5,725,092 5,897,594 Unamortized PSNH acquisition costs......................... 402,285 491,709 Construction work in progress.............................. 141,077 146,438 Nuclear fuel, net.......................................... 194,704 196,424 ------------ ------------ Total net utility plant................................ 6,463,158 6,732,165 ------------ ------------ Other Property and Investments: Nuclear decommissioning trusts, at market.................. 502,749 403,544 Investments in regional nuclear generating companies, at equity................................................ 86,955 85,340 Investments in transmission companies, at equity........... 19,635 21,186 Investments in Charter Oak Energy, Inc..................... - 57,188 Other, at cost............................................. 95,362 43,372 ------------ ------------ 704,701 610,630 ------------ ------------ Current Assets: Cash and cash equivalents.................................. 143,403 194,197 Investments in securitizable assets........................ 230,905 - Receivables,less accumulated provision for uncollectible accounts of $2,052,000 in 1997 and $17,062,000 in 1996... 214,914 477,021 Accrued utility revenues................................... 36,885 127,162 Fuel, materials, and supplies, at average cost............. 212,721 211,414 Recoverable energy costs, net--current portion............. 59,959 1,804 Investments in Charter Oak Energy, Inc. held for sale...... 33,391 - Prepayments and other...................................... 38,495 55,318 ------------ ------------ 970,673 1,066,916 ------------ ------------ Deferred Charges: Regulatory assets.......................................... 2,173,278 2,221,839 Unamortized debt expense................................... 38,758 38,146 Other ..................................................... 63,844 72,052 ------------ ------------ 2,275,880 2,332,037 ------------ ------------ Total Assets................................................. $10,414,412 $10,741,748 ============ ============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Balance Sheets
Capitalization and Liabilities: - ------------------------------- Capitalization: (See Consolidated Statements of Capitalization) Common shareholders' equity (See Note (a) - Consolidated Statements of Common Shareholders' Equity): Common shares, $5 par value--authorized 225,000,000 shares;136,842,170 shares issued and 130,182,736 shares outstanding in 1997 and 136,051,938 shares issued and 128,444,373 shares outstanding in 1996........ $ 684,211 $ 680,260 Capital surplus, paid in................................... 932,493 940,446 Deferred contribution plan--employee stock ownership plan (ESOP).............................................. (154,141) (176,091) Retained earnings (Note 1)................................. 707,522 869,618 ------------ ------------ Total common shareholders' equity........................ 2,170,085 2,314,233 Preferred stock not subject to mandatory redemption.......... 136,200 136,200 Preferred stock subject to mandatory redemption.............. 245,750 276,000 Long-term debt............................................... 3,645,659 3,613,681 ------------ ------------ Total capitalization..................................... 6,197,694 6,340,114 ------------ ------------ Minority Interest in Consolidated Subsidiaries................. 100,000 99,972 ------------ ------------ Obligations Under Capital Leases............................... 30,427 186,860 ------------ ------------ Current Liabilities: Notes payable to banks....................................... 50,000 38,750 Long-term debt and preferred stock--current portion.......... 274,810 319,503 Obligations under capital leases--current portion............ 177,304 19,305 Accounts payable............................................. 402,870 507,139 Accrued taxes................................................ 46,016 7,050 Accrued interest............................................. 30,786 51,386 Accrued pension benefits..................................... 77,186 99,699 Other........................................................ 88,396 98,570 ------------ ------------ 1,147,368 1,141,402 ------------ ------------ Deferred Credits: Accumulated deferred income taxes............................ 1,984,513 2,070,225 Accumulated deferred investment tax credits.................. 158,837 168,444 Deferred contractual obligations............................. 525,076 440,495 Other........................................................ 270,497 294,236 ------------ ------------ 2,938,923 2,973,400 ------------ ------------ Commitments and Contingencies (Note 8) Total Capitalization and Liabilities........................... $10,414,412 $10,741,748 ============ ============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Income
- -------------------------------------------------------------------------------------------- For the Years Ended December 31, - -------------------------------------------------------------------------------------------- (Thousands of Dollars, except share 1997 1996 information) (Restated) (Restated) 1995 - -------------------------------------------------------------------------------------------- Operating Revenues................................ $ 3,834,806 $ 3,792,148 $ 3,750,560 ------------- ------------- ------------- Operating Expenses: Operation -- Fuel, purchased and net interchange power..... 1,293,518 1,139,848 909,244 Other......................................... 1,097,297 1,094,078 966,845 Maintenance..................................... 501,693 415,532 288,927 Depreciation.................................... 354,329 359,507 354,293 Amortization of regulatory assets, net.......... 130,900 122,573 128,413 Federal and state income taxes (See Consolidated Statements of Income Taxes)....... 12,650 94,363 261,287 Taxes other than income taxes................... 253,637 257,577 249,463 ------------- ------------- ------------- Total operating expenses (Note 1)........... 3,644,024 3,483,478 3,158,472 ------------- ------------- ------------- Operating Income.................................. 190,782 308,670 592,088 ------------- ------------- ------------- Other Income: Deferred nuclear plants return--other funds..... 7,288 8,988 14,196 Equity in earnings of regional nuclear generating and transmission companies......... 11,306 13,155 13,208 Other, net...................................... (38,473) 30,932 10,954 Minority interest in income of subsidiary....... (9,300) (9,300) (8,732) Income taxes.................................... 10,702 (1,747) (683) ------------- ------------- ------------- Other (loss)/ income, net................... (18,477) 42,028 28,943 ------------- ------------- ------------- Income before interest charges.............. 172,305 350,698 621,031 ------------- ------------- ------------- Interest Charges: Interest on long-term debt...................... 282,095 285,463 315,862 Other interest.................................. 3,561 7,649 6,666 Deferred nuclear plants return--borrowed funds.. (13,675) (15,119) (23,310) ------------- ------------- ------------- Interest charges, net....................... 271,981 277,993 299,218 ------------- ------------- ------------- (Loss)/Income after interest charges......... (99,676) 72,705 321,813 Preferred Dividends of Subsidiaries............... 30,286 33,776 39,379 ------------- ------------- ------------- Net (Loss)/Income (Note 1)........................ $ (129,962) $ 38,929 $ 282,434 ============= ============= ============= (Loss)/Earnings Per Common Share (Note 1)......... $ (1.01) $ 0.30 $ 2.24 ============= ============= ============= Common Shares Outstanding (average)............... 129,567,708 127,960,382 126,083,645 ============= ============= =============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Cash Flows
- ------------------------------------------------------------------------------------------------ For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) - ------------------------------------------------------------------------------------------------ (Thousands of Dollars) Operating Activities: (Loss)/Income before preferred dividends of subsidiaries..... $ (99,676) $ 72,705 $ 321,813 Adjustments to reconcile to net cash from operating activities: Depreciation............................................... 354,329 359,507 354,293 Deferred income taxes and investment tax credits, net...... 26,435 71,832 164,208 Deferred nuclear plants return, net of amortization........ (13,781) (14,948) 71,788 Amortization of demand-side-management costs, net.......... 38,029 26,941 (937) Recoverable energy costs, net of amortization.............. (54,102) (14,289) (27,874) Amortization of PSNH acquisition costs..................... 56,557 56,884 55,547 Amortization of deferred cogeneration costs, net........... 32,700 25,957 (55,341) Deferred nuclear refueling outage, net of amortization..... (36,514) 51,831 (29,569) Other sources of cash...................................... 141,041 164,915 147,348 Other uses of cash......................................... (86,202) (41,589) (67,838) Changes in working capital: Receivables and accrued utility revenues .................. 262,384 (31,992) (72,081) Fuel, materials, and supplies.............................. (1,307) (10,834) (10,518) Accounts payable........................................... (104,269) 188,101 38,096 Accrued taxes.............................................. 38,966 (68,168) 17,686 Sale of receivables and accrued utility revenues........... 90,000 - - Investments in securitizable assets........................ (230,905) - - Other working capital (excludes cash)...................... (36,464) (21,383) (2,458) ---------- ---------- ---------- Net cash flows from operating activities (Note 1).............. 377,221 815,470 904,163 ---------- ---------- ---------- Financing Activities: Issuance of common shares.................................... 6,502 10,622 31,976 Issuance of long-term debt................................... 260,000 222,150 225,100 Issuance of Monthly Income Preferred Securities........................................ - - 100,000 Net increase/(decrease) in short-term debt................... 11,250 (60,250) (91,000) Reacquisitions and retirements of long-term debt............. (288,793) (248,142) (425,500) Reacquisitions and retirements of preferred stock............ (25,000) (36,500) (140,675) Cash dividends on preferred stock............................ (30,286) (33,776) (39,379) Cash dividends on common shares.............................. (32,134) (176,277) (221,701) ---------- ---------- ---------- Net cash flows used for financing activities................... (98,461) (322,173) (561,179) ---------- ---------- ---------- Investment Activities: Investment in plant: Electric and other utility plant........................... (233,399) (222,829) (231,408) Nuclear fuel............................................... (6,852) (14,529) (18,261) ---------- ---------- ---------- Net cash flows used for investments in plant................. (240,251) (237,358) (249,669) Investment in nuclear decommissioning trusts................. (61,046) (65,716) (60,642) Other investment activities, net............................. (28,257) (25,064) (30,761) ---------- ---------- ---------- Net cash flows used for investments............................ (329,554) (328,138) (341,072) ---------- ---------- ---------- Net (Decrease)/Increase In Cash For The Period................. (50,794) 165,159 1,912 Cash and cash equivalents - beginning of period................ 194,197 29,038 27,126 ---------- ---------- ---------- Cash and cash equivalents - end of period...................... $ 143,403 $ 194,197 $ 29,038 ========== ========== ========== Supplemental Cash Flow Information: Cash paid/(refunded) during the year for: Interest, net of amounts capitalized......................... $ 291,335 $ 268,129 $ 321,148 ========== ========== ========== Income taxes................................................. $ (26,387) $ 64,189 $ 108,928 ========== ========== ========== Increase in obligations: Niantic Bay Fuel Trust and other capital leases.............. $ 3,475 $ 3,524 $ 41,388 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Shareholders' Equity
- --------------------------------------------------------------------------------------------------------- Capital Deferred Retained Common Surplus, Contribution Earnings (b) Shares(a) Paid In Plan--ESOP (Note 1) Total - --------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Balance as of January 1, 1995............... $ 671,051 $904,371 $ (213,324) $ 946,988 $2,309,086 ---------- --------- ------------- ------------- ----------- Net income for 1995...................... 282,434 282,434 Cash dividends on common shares-- $1.76 per share....................... (221,701) (221,701) Loss on retirement of preferred stock.... (381) (381) Issuance of 1,400,940 common shares, $5 par value........................... 7,005 24,971 31,976 Allocation of benefits-- ESOP............ 70 15,172 15,242 Capital stock expenses, net.............. 6,896 6,896 ---------- --------- ------------- ------------- ----------- Balance as of December 31, 1995............. 678,056 936,308 (198,152) 1,007,340 2,423,552 ---------- --------- ------------- ------------- ----------- Net income for 1996 (Note 1)............. 38,929 38,929 Cash dividends on common shares-- $1.38 per share....................... (176,277) (176,277) Loss on retirement of preferred stock.... (374) (374) Issuance of 440,772 common shares, $5 par value........................... 2,204 8,418 10,622 Allocation of benefits-- ESOP............ (8,103) 22,061 13,958 Capital stock expenses, net.............. 3,077 3,077 Currency translation adjustments......... 746 746 ---------- --------- ------------- ------------- ----------- Balance as of December 31, 1996 (Restated).. 680,260 940,446 (176,091) 869,618 2,314,233 ---------- --------- ------------- ------------- ----------- Net loss for 1997 (Note 1)............... (129,962) (129,962) Cash dividends on common shares-- $0.25 per share....................... (32,134) (32,134) Issuance of 790,232 common shares, $5 par value........................... 3,951 2,551 6,502 Allocation of benefits-- ESOP............ (12,238) 21,950 9,712 Capital stock expenses, net.............. 2,592 2,592 Currency translation adjustments......... (858) (858) ---------- --------- ------------- ------------- ----------- Balance as of December 31, 1997 (Restated).. $ 684,211 $932,493 $ (154,141) $ 707,522 $2,170,085 ========== ========= ============= ============= =========== (a) NU issued 8,430,910 warrants as part of its acquisition of PSNH. These warrants, which expired on June 5, 1997, entitled the holder to purchase one share of NU common stock at an exercise price of $24 per share. As of June 5, 1997, 464,678 shares had been purchased through the exercise of warrants. (b) Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt agreements. These restrictions also limit the amount of retained earnings available for NU common dividends. At December 31, 1997, these restrictions totaled approximately $559.6 million. The accompanying notes are an integral part of these financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Capitalization
- ------------------------------------------------------------------------------------------------------- At December 31, - ------------------------------------------------------------------------------------------------------- 1997 1996 (Thousands of Dollars) (Restated) (Restated) - ------------------------------------------------------------------------------------------------------- Common Shareholders' Equity (See Consolidated Balance Sheets).................. $2,170,085 $2,314,233 - ------------------------------------------------------------------------------------------------------- Cumulative Preferred Stock of Subisidiaries: $25 par value--authorized 36,600,000 shares at December 31, 1997 and 1996; 4,840,000 shares outstanding in 1997 and 5,840,000 shares outstanding in 1996 $50 par value--authorized 9,000,000 shares at December 31, 1997 and 1996; 5,424,000 shares outstanding in 1997 and 5,424,000 shares outstanding in 1996 $100 par value--authorized 1,000,000 shares at December 31, 1997 and 1996; 200,000 shares outstanding in 1997 and 1996 - ------------------------------------------------------------------------------------------------------- Current Current Dividend Rates Redemption Prices(a) Shares Outstanding - ------------------------------------------------------------------------------------------------------- Not Subject to Mandatory Redemption: $50 par value--$1.90 to $3.28 $50.50 to $54.00 2,324,000...... 116,200 116,200 $100 par value--$7.72 $103.51 200,000...... 20,000 20,000 - ------------------------------------------------------------------------------------------------------- Total Preferred Stock Not Subject to Mandatory Redemption...................... 136,200 136,200 - ------------------------------------------------------------------------------------------------------- Subject to Mandatory Redemption: (b) $25 par value--$1.90 to $2.65 $25.00 to $25.64 4,840,000...... 121,000 146,000 $50 par value--$2.65 to $3.615 $51.00 to $52.41 3,100,000...... 155,000 155,000 - ------------------------------------------------------------------------------------------------------- Total Preferred Stock Subject to Mandatory Redemption.......................... 276,000 301,000 Less:Preferred Stock to be redeemed within one year............................ 30,250 25,000 - ------------------------------------------------------------------------------------------------------- Preferred Stock Subject to Mandatory Redemption,net............................ 245,750 276,000 - ------------------------------------------------------------------------------------------------------- Long-term Debt: (c) First Mortgage Bonds-- Maturity Interest Rates - ------------------------------------------------------------------------------------------------------- 1997 5.75% to 7.625%.......................................... - 207,988 1998 6.50% to 9.17%........................................... 199,800 199,800 1999 5.50% to 7.25%........................................... 279,000 279,000 2000 5.75% to 6.875%.......................................... 260,000 260,000 2001 7.375% to 7.875%......................................... 220,000 160,000 2002 7.75% to 9.05%........................................... 580,000 400,000 2004 6.125%................................................... 140,000 140,000 2019-2023 7.375% to 7.50%.......................................... 120,000 120,000 2024-2025 7.375% to 8.50%.......................................... 430,000 430,000 - ------------------------------------------------------------------------------------------------------- Total First Mortgage Bonds 2,228,800 2,196,788 - ------------------------------------------------------------------------------------------------------- Other Long-Term Debt --(d) Pollution Control Notes and Other Notes-- 2000 Adjustable Rate (e) and 7.67%............................ 218,033 224,182 2005-2006 8.38% to 8.58%........................................... 194,000 210,000 2013-2018 Adjustable Rate.......................................... 33,400 33,400 2020 Adjustable Rate.......................................... 15,300 15,300 2021-2022 7.50% to 7.65% and Adjustable Rate....................... 552,485 552,485 2028 Adjustable Rate.......................................... 369,300 369,300 2031 Adjustable Rate.......................................... 62,000 62,000 - ------------------------------------------------------------------------------------------------------- Total Pollution Control Notes and Other Notes................................. 1,444,518 1,466,667 Fees and interest due for spent nuclear fuel disposal costs (Note 2P).......... 205,502 195,023 Other.......................................................................... 18,513 57,169 - ------------------------------------------------------------------------------------------------------- Total Other Long-Term Debt..................................................... 1,668,533 1,718,859 - ------------------------------------------------------------------------------------------------------- Unamortized premium and discount, net.......................................... (7,113) (7,463) - ------------------------------------------------------------------------------------------------------- Total Long-Term Debt........................................................... 3,890,220 3,908,184 Less: Amounts due within one year.............................................. 244,561 294,503 - ------------------------------------------------------------------------------------------------------- Long-Term Debt, net............................................................ 3,645,659 3,613,681 - ------------------------------------------------------------------------------------------------------- Total Capitalization........................................................... $6,197,694 $6,340,114 ======================================================================================================= The accompanying notes are an integral part of these financial statements.
Notes to Consolidated Statements of Capitalization (a) Each of these series is subject to certain refunding limitations for the first five years after issuance. Redemption prices reduce in future years. (b) Changes in Preferred Stock Subject to Mandatory Redemption: - ---------------------------------------------------------------------------- (Thousands of Dollars) - ---------------------------------------------------------------------------- Balance at January 1, 1995 .............................. $ 379,675 Reacquisitions and Retirements .......................... (75,675) - ---------------------------------------------------------------------------- Balance at December 31, 1995 ............................ 304,000 Reacquisitions and Retirements .......................... (3,000) - ---------------------------------------------------------------------------- Balance at December 31, 1996 ............................ 301,000 Reacquisitions and Retirements .......................... (25,000) - ---------------------------------------------------------------------------- Balance at December 31, 1997 ............................ $ 276,000 ============================================================================ The minimum sinking-fund requirements of the series subject each year to mandatory redemption aggregate approximately $30.3 million in 1998, $46.3 million each year in 1999, 2000 and 2001 and $21.3 million in 2002. In case of default on sinking-fund payments, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If a subsidiary is in arrears in the payment of dividends on any outstanding shares of preferred stock, the subsidiary is prohibited from redeeming or purchasing less than all of the outstanding preferred stock. (c) Long-term debt maturities and cash sinking-fund requirements, excluding fees and interest due for spent nuclear fuel disposal costs, on debt outstanding at December 31, 1997, for the years 1998 through 2002 are approximately $244.6 million, $375.9 million, $557.8 million, $313.2 million and $375.4 million, respectively. In addition, there are annual one percent sinking- and improvement-fund requirements of approximately $1.5 million each year for 1998 and 1999 and $900 thousand each year for 2000 through 2002 for certain series of Western Massachusetts Electric Company (WMECO) first mortgage bonds. The WMECO sinking- and improvement-fund requirements may be satisfied by the deposit of cash or bonds or by certification of property additions. The one percent sinking- and improvement-fund requirements for The Connecticut Light and Power Company (CL&P) first mortgage bonds are no longer required, as of 1997, as determined by a majority of bond holders. Essentially all utility plant of CL&P, WMECO, Public Service Company of New Hampshire (PSNH) and North Atlantic Energy Corporation (NAEC), wholly owned subsidiaries of NU, is subject to the liens of each company's respective first mortgage bond indenture. NAEC's first mortgage bonds also are secured by payments made to NAEC by PSNH under the terms of the Seabrook Power Contracts. CL&P and WMECO have secured $369.3 million of pollution-control notes with second mortgage liens on Millstone 1, junior to the liens of their respective first mortgage bond indentures. CL&P and WMECO have issued $225 million and $90 million, respectively, of first mortgage bonds as collateral to enable them to borrow under a three-year revolving credit agreement. At December 31, 1997, CL&P and WMECO had $35 million and $15 million, respectively, in borrowings under this agreement. PSNH's Revolving Credit Facility has a second lien, junior to the lien of its first mortgage bond indenture, on all PSNH property located in New Hampshire, which will expire in April 1999. At December 31, 1997, PSNH had no borrowings under the Revolving Credit Facility. For further information on these borrowing facilities, see Note 4, "Short-Term Debt." CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) with a bond insurance and liquidity facility secured by first mortgage bonds. Concurrent with the issuance of PSNH's Series A and B first mortgage bonds, PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the state of New Hampshire. Pursuant to these arrangements, the BFA issued seven series of PCRBs and loaned the proceeds to PSNH. At December 31, 1997, $516.5 million of the PCRBs were outstanding. PSNH's obligation to repay each series of PCRBs is secured by a series of first mortgage bonds that were issued under its indenture. Each such series of first mortgage bonds contains terms and provisions with respect to maturity, principal payment, interest rate and redemption that correspond to those of the applicable series of PCRBs. For financial reporting purposes, these bonds would not be considered outstanding unless PSNH fails to meet its obligations under the PCRBs. (d) The average effective interest rates on the variable-rate pollution control notes ranged from 3.4 percent to 5.6 percent for 1997 and 3.2 percent to 5.5 percent for 1996. (e) Interest-rate management instruments with financial institutions effectively fix the interest rate of NAEC's $200 million variable-rate bank note at 7.823 percent. For further information, see Note 9, "Market Risk Management." Consolidated Statements of Income Taxes
- -------------------------------------------------------------------------------------- For the Years Ended December 31, - -------------------------------------------------------------------------------------- 1997 1996 (Thousands of Dollars) (Restated) (Restated) 1995 - -------------------------------------------------------------------------------------- The components of the federal and state income tax provisions (credited)/charged to operations are: Current income taxes Federal......................................... $ (22,760) $ 13,500 $ 53,862 State........................................... (1,727) 10,778 43,900 - -------------------------------------------------------------------------------------- Total current..................................... (24,487) 24,278 97,762 - -------------------------------------------------------------------------------------- Deferred income taxes, net Federal......................................... 46,871 90,093 167,091 State........................................... (10,841) (8,667) 7,224 - -------------------------------------------------------------------------------------- Total deferred.................................... 36,030 81,426 174,315 - -------------------------------------------------------------------------------------- Investment tax credits, net....................... (9,595) (9,594) (10,107) - -------------------------------------------------------------------------------------- Total income tax expense (Note 1)................. $ 1,948 $ 96,110 $ 261,970 ====================================================================================== The components of total income tax expense are classified as follows: Income taxes charged to operating expenses...... $ 12,650 $ 94,363 $ 261,287 Other income taxes.............................. (10,702) 1,747 683 - -------------------------------------------------------------------------------------- Total income tax expense.......................... $ 1,948 $ 96,110 $ 261,970 ====================================================================================== Deferred income taxes comprise the tax effects of temporary differences as follows: Depreciation, leased nuclear fuel, settlement credits and disposal costs..................... $ 32,932 $ 18,401 $ 82,318 Energy adjustment clauses....................... 5,916 (8,268) 26,851 Nuclear plant deferrals......................... 13,989 (15,549) 2,666 Contractual settlements......................... 1,754 2,513 (9,496) Bond redemptions................................ (4,260) (4,685) 9,224 Amortization of New Hampshire regulatory settlement..................................... 11,501 11,501 11,501 Deferred tax asset associated with net operating losses............................... - 96,756 57,543 Demand-side management.......................... (12,169) (14,954) 765 State net operating loss carryforward........... (7,670) - - Other........................................... (5,963) (4,289) (7,057) - -------------------------------------------------------------------------------------- Deferred income taxes, net........................ $ 36,030 $ 81,426 $ 174,315 ====================================================================================== A reconciliation between income tax expense and the expected tax expense at 35 percent of pretax income: Expected federal income tax....................... $ (34,205) $ 59,085 $ 204,324 Tax effect of differences: Depreciation.................................... 22,049 24,337 25,639 Deferred nuclear plants return.................. (2,551) (3,146) (4,969) Amortization of regulatory assets............... 5,498 7,910 20,389 Amortization of PSNH acquisitions costs......... 31,298 31,410 31,522 Seabrook intercompany loss...................... (4,616) (7,503) (13,048) Investment tax credit amortization.............. (9,595) (9,594) (10,107) State income taxes, net of federal benefit...... (7,839) 1,372 33,231 Sale of Seabrook 2 steam generator.............. - (2,516) - Adjustment for prior years' taxes............... (1,712) (962) (20,312) Employee stock ownership plan................... (4,648) (4,007) (2,192) Dividends received deduction.................... (1,563) (3,027) (3,936) Loss reserve on sale of investment.............. 8,750 - - Other, net...................................... 1,082 2,751 1,429 - -------------------------------------------------------------------------------------- Total income tax expense.......................... $ 1,948 $ 96,110 $ 261,970 ====================================================================================== The accompanying notes are an integral part of these financial statements.
Notes to Consolidated Financial Statements 1. Securities and Exchange Commission Inquiry In a letter dated March 25, 1998, the Securities and Exchange Commission (SEC) inquired into Northeast Utilities' (NU or the company) accounting for nuclear compliance costs. These costs are the unavoidable incremental costs associated with the current nuclear outages required to be incurred prior to restart of the units in accordance with correspondence received from the Nuclear Regulatory Commission (NRC) early in 1996. The SEC's view is that these unavoidable costs associated with nuclear outages and procedures to be implemented at nuclear power plants in response to regulatory requirements required prior to restart of the units should be expensed as incurred. During 1996 and 1997, NU and its wholly owned subsidiaries, CL&P, PSNH and WMECO reserved for these unavoidable incremental costs that they expected to incur to meet NRC standards. The SEC advised NU, CL&P, PSNH and WMECO to reflect these costs as they are incurred. While NU and its independent auditors, Arthur Andersen LLP, believed the accounting was required by, and was in accordance with, generally accepted accounting principles, the company has agreed to adjust its accounting for nuclear compliance costs and amend its 1996 and 1997 Form 10-K filings. The financial statements in this report have been restated to reflect the change in accounting. 2. Summary of Significant Accounting Policies A. About Northeast Utilities NU is the parent company of the Northeast Utilities system (the NU system). The NU system furnishes franchised retail electric service in Connecticut, New Hampshire and western Massachusetts through four wholly owned subsidiaries: CL&P, PSNH, WMECO and Holyoke Water Power Company (HWP). A fifth wholly owned subsidiary, NAEC, sells all of its entitlement to the capacity and output of the Seabrook nuclear power plant (Seabrook) to PSNH. In addition to its franchised retail service, the NU system furnishes firm and other wholesale electric services to various municipalities and other utilities, and participates in limited retail access programs, providing off-system retail electric service. The NU system serves about 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues. Several wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing and other services to the NU system companies. Northeast Nuclear Energy Company (NNECO) acts as agent for the NU system companies and other New England utilities in operating the Millstone nuclear generating facilities. North Atlantic Energy Service Corporation (NAESCO) has operational responsibility for Seabrook. Three other subsidiaries construct, acquire or lease some of the property and facilities used by the NU system companies. In addition, CL&P and WMECO each have established a special purpose subsidiary whose business consists of the purchase and resale of receivables. Charter Oak Energy, Inc. (COE), HEC, Inc. (HEC), Mode 1 Communications, Inc. (Mode 1), and Select Energy, Inc., (formerly NUSCO Energy Partners, Inc.) are other NU system companies which engage in a variety of activities. Directly and through subsidiaries, COE has investments in cogeneration, small-power production and other forms of nonutility generation as permitted under the Public Utility Regulatory Policy Act, and in exempt wholesale generators and foreign utility companies as permitted under the Energy Policy Act of 1992 (Energy Act). These investments are accounted for on either a cost or equity basis based upon COE's level of participation. NU has put COE up for sale. For further information regarding the sale of COE, see Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), and Note 8G, "Commitments and Contingencies -- Sale of COE." HEC provides energy management services for the NU system's and other utilities' commercial, industrial and institutional electric customers. Mode 1 and Select Energy, Inc. develop and invest in telecommunications and in energy-related activities, respectively. B. Presentation The consolidated financial statements of the company include the accounts of all wholly owned subsidiaries. Significant intercompany transactions have been eliminated in consolidation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. C. Public Utility Regulation NU is registered with the SEC as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act). NU and its subsidiaries are subject to the provisions of the 1935 Act. Arrangements among the NU system companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. The operating subsidiaries are subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions. For information regarding proposed changes in the nature of industry regulation, see Note 8A, "Commitments and Contingencies -- Restructuring and Rate Matters." D. New Accounting Standards The Financial Accounting Standards Board (FASB) issued two new accounting standards in February 1997: Statement of Financial Accounting Standards (SFAS) 128, "Earnings per Share" and SFAS 129, "Disclosure of Information about Capital Structure." SFAS 128 establishes standards for computing and presenting earnings per share (EPS) and is effective for 1997. The adoption of SFAS 128 did not have a material impact on the company's EPS calculation and presentation. SFAS 129 establishes standards for disclosing information about an entity's capital structure. NU's current disclosures are consistent with the requirements of SFAS 129. During June 1997, the FASB issued SFAS 130, "Reporting Comprehensive Income" and SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." SFAS 130 establishes standards for the reporting and disclosure of comprehensive income. To date, the NU system companies have not had material transactions that would be required to be reported as comprehensive income. SFAS 131 determines the standards for reporting and disclosing qualitative and quantitative information about a company's operating segments. This information includes segment profit or loss, certain segment revenue and expense items and segment assets and a reconciliation of these segment disclosures to corresponding amounts in the company's general purpose financial statements. The NU system currently evaluates management performance using a cost-based budget, and the information required by SFAS 131 is not available. Therefore, these disclosure requirements are not applicable. Management believes that the implementation of SFAS 130 and SFAS 131 will not have a material impact on NU's current disclosures. See Note 7, "Sale of Customer Receivables and Accrued Utility Revenues," and Note 8C, "Commitments and Contingencies -- Environmental Matters," for information on other newly issued accounting and reporting standards related to those specific areas. E. Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock of four regional nuclear generating companies (Yankee companies). The NU system's investments in the Yankee companies are accounted for on the equity basis due to NU's ability to exercise significant influence over their operating and financial policies. The Yankee companies, with the NU system's equity investments and ownership interests are: - ---------------------------------------------------------------------------- (Thousands of Dollars Except for Percentages) - ---------------------------------------------------------------------------- Connecticut Yankee Atomic Power Company (CYAPC) $54,671 49.0% Yankee Atomic Electric Company (YAEC) 8,020 38.5 Maine Yankee Atomic Power Company (MYAPC) 15,699 20.0 Vermont Yankee Nuclear Power Corporation (VYNPC) 8,565 16.0 - ---------------------------------------------------------------------------- Total Equity Investment $86,955 ============================================================================ Each Yankee company owns a single nuclear generating unit. Under the terms of the contracts with the Yankee companies, the shareholders-sponsors are responsible for their proportionate share of the costs of each unit, including decommissioning. The energy and capacity costs from VYNPC and nuclear decommissioning costs of the Yankee companies that have been shut down are billed as purchased power to CL&P, PSNH and WMECO. The electricity produced by the Vermont Yankee nuclear generating facility (VY) is committed substantially on the basis of ownership interests and is billed pursuant to contractual agreements. YAEC's, CYAPC's and MYAPC's nuclear power plants were shut down permanently on February 26, 1992, December 4, 1996, and August 6, 1997, respectively. Under ownership agreements with the Yankee companies, CL&P, PSNH and WMECO may be asked to provide direct or indirect financial support for one or more of the companies. For more information on the Yankee companies, see Note 3, "Nuclear Decommissioning," and Note 8F, "Commitments and Contingencies -- Long-Term Contractual Arrangements." Millstone: CL&P and WMECO together own 100 percent of both Millstone 1, a 660- megawatt (MW) nuclear generating unit and Millstone 2, a 870-MW nuclear generating unit. CL&P, PSNH and WMECO together have a 68.02 percent joint ownership interest in Millstone 3, a 1,154-MW nuclear generating unit. The three Millstone units are out of service. NU hopes to return Millstone 3 to service in early spring of 1998 and Millstone 2 three to four months after Millstone 3. Millstone 1 has been placed in extended maintenance status. Management is reviewing its options with respect to Millstone 1, including restart, early retirement and other options. In a draft ruling issued in February 1998, the Connecticut Department of Public Utility Control (DPUC) determined that Millstone 1 was no longer "used and useful" and ordered it removed from rate base. In 1996, one of the joint owners of Millstone 3, Vermont Electric Generation and Transmission Cooperative, Inc. (VEG&T), filed for bankruptcy. The subsequent liquidation resulted in the offering of VEG&T's 0.035 percent share of Millstone 3 for sale to the joint owners of Millstone 3. None of the non-NU joint owners accepted the offer. During 1998, CL&P expects to make the necessary regulatory filings to acquire ownership of VEG&T's share of Millstone 3. For more information regarding the DPUC's action, see the MD&A. For more information regarding the Millstone units see Note 3, "Nuclear Decommissioning," and Note 8B, "Commitments and Contingencies -- Nuclear Performance." Seabrook 1: CL&P and NAEC together have a 40.04 percent joint ownership interest in Seabrook 1, a 1,148-MW nuclear generating unit. NAEC sells all of its share of the power generated by Seabrook 1 to PSNH under two long-term contracts (the Seabrook Power Contracts). Plant-in-service and the accumulated provision for depreciation for the NU system's share of the three Millstone units and Seabrook 1 are as follows: - ----------------------------------------------------------------------------- At December 31, - ----------------------------------------------------------------------------- (Millions of Dollars) 1997 1996 - ----------------------------------------------------------------------------- Plant-in-service Millstone 1 $ 478.7 $ 474.7 Millstone 2 857.1 851.8 Millstone 3 2,404.3 2,402.4 Seabrook 1 897.5 892.4 Accumulated provision for depreciation Millstone 1 $ 212.1 $ 196.6 Millstone 2 306.7 275.8 Millstone 3 695.1 633.3 Seabrook 1 150.0 131.7 ============================================================================= The NU system's share of Millstone and Seabrook 1 expenses are included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling approximately $19.6 million, in two companies that transmit electricity imported from the Hydro-Quebec system in Canada. The two companies own and operate transmission and terminal facilities which have the capability of importing up to 2,000 MW from the Hydro-Quebec system. See Note 8F, "Commitments and Contingencies -- Long-Term Contractual Arrangements," for additional information. F. Depreciation The provision for depreciation is calculated using the straight-line method based on estimated remaining lives of depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency. Except for major facilities, depreciation rates are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.8 percent in 1997, 1996 and 1995. See Note 3, "Nuclear Decommissioning," for information on nuclear plant decommissioning. The NU system's nonnuclear generating facilities have limited service lives. Plant may be retired in place or dismantled based upon expected future needs, the economics of the closure and environmental concerns. The costs of closure and removal are incremental costs and, for financial reporting purposes, are accrued over the life of the asset as part of depreciation. At December 31, 1997 and 1996, the accumulated provision for depreciation included approximately $83.2 million and $77.3 million, respectively, accrued for the cost of removal, net of salvage for nonnuclear generation property. G. Revenues Other than revenues under fixed-rate agreements negotiated with certain wholesale, commercial and industrial customers and limited retail access programs, utility revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission. Regulatory commissions also have authority over the terms and conditions of nontraditional rate-making arrangements. At the end of each accounting period, CL&P, PSNH and WMECO accrue an estimate for the amount of energy delivered but unbilled. For information on rate proceedings and their potential impact on CL&P and PSNH, see the MD&A. H. Regulatory Accounting and Assets The accounting policies of the operating companies and the accompanying consolidated financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered through future revenues. Through their actions, regulators also may reduce or eliminate the value of an asset, or create a liability. If any portion of the operating companies' operations were no longer subject to the provisions of SFAS 71, as a result of a change in the cost-of-service based regulatory structure or the effects of competition, the company would be required to write off all of its related regulatory assets and liabilities unless there is a formal transition plan which provides for the recovery, through established rates, for the collection of approved stranded costs and to maintain the cost-of-service basis for the remaining regulated operations. At the time of transition, the operating companies would be required to determine any impairment to the carrying costs of deregulated plant and inventory assets. Management anticipates that restructuring programs will be implemented within each of the NU system operating companies' respective jurisdictions during the next few years. In a restructured environment, the companies' generation businesses no longer will be rate regulated on a cost-of-service basis. The majority of NU's regulatory assets are related to its generation business. The staff of the SEC has had concerns regarding the appropriateness of the utilities' ability to continue application of SFAS 71 for the generation portion of their business in a restructured environment. The SEC referred the issue to the Emerging Issues Task Force (EITF) of the FASB which reached a consensus and issued "Deregulation of the Pricing of Electricity-Issues Related to the Application of FASB Statements No. 71 and 101" (EITF 97-4). The EITF concluded: (1) the future recognition of regulatory assets for the portion of the business that no longer qualifies for application of SFAS 71 depends on the regulators' treatment of the recovery of those costs and other stranded assets from cash flows of other portions of the business still considered to be regulated, and (2) a utility should discontinue the application of SFAS 71 when a legislative and regulatory plan has been enacted, which would include transition plans into a competitive environment, and when the stranded costs which are subject to future rate recovery are determined. EITF 97-4 became effective in August 1997. Electric utility industry restructuring within the state of Massachusetts will be effective March 1, 1998. WMECO has submitted its proposed restructuring plan to the Massachusetts Department of Telecommunications and Energy (DTE), formerly the Massachusetts Department of Public Utilities. If the DTE approves the plan in its current form, WMECO would discontinue the application of SFAS 71. However, the restructuring legislation enacted by the state of Massachusetts specifically provides for future deferrals and the cost recovery of generation- related assets as contemplated under the plan. As such, WMECO is not expected to have to write off either its generation-related assets or related regulatory assets. WMECO's generation-related regulatory assets were valued at approximately $188 million at December 31, 1997. The issue of restructuring the electric utility industry in New Hampshire is currently the focus of negotiations and proceedings within the federal and state court systems. Management believes that PSNH's use of regulatory accounting remains appropriate while this issue remains in litigation. The Connecticut General Assembly is addressing a proposal for electric industry restructuring in the state of Connecticut during 1998. As the terms and conditions to be contained within the restructuring plan cannot be determined at this time, management believes that its use of regulatory accounting within this jurisdiction remains appropriate. The company expects that its transmission and distribution business within each of its jurisdictions will continue to be rate regulated on a cost-of-service basis and, accordingly, CL&P, WMECO and PSNH will continue to apply SFAS 71 to this portion of their business. For further information on the NU system companies' respective regulatory environments and the potential impacts of restructuring, see Note 8A, "Commitments and Contingencies -- Restructuring and Rate Matters" and the MD&A. SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires the evaluation of long-lived assets, including regulatory assets, for impairment when certain events occur or when conditions exist that indicate the carrying amounts of assets may not be recoverable. SFAS 121 requires that any long-lived assets which are no longer probable of recovery through future revenues be revalued based on estimated future cash flows. If this revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. Management continues to believe it is probable that the operating companies will recover their investments in long-lived assets through future revenues. This conclusion may change in the future as the implementation of restructuring plans within the NU system companies' respective jurisdictions will generally require the formation of separate generation entities that will be subject to competitive market conditions. As a result, the NU system companies will be required to assess the carrying amounts of their long-lived assets in accordance with SFAS 121. The components of the NU system companies' regulatory assets are as follows: - ---------------------------------------------------------------------------- At December 31, - ---------------------------------------------------------------------------- (Thousands of Dollars) 1997 1996 Income taxes, net (Note 2I) $ 938,564 $1,012,343 Recoverable energy costs, net (Note 2K) 324,809 328,863 Deferred costs -- nuclear plants (Note 2L) 199,753 185,078 Unrecovered contractual obligations (Note 3) 515,076 435,495 Deferred demand-side management costs (Note 2M) 52,100 90,129 Cogeneration costs (Note 2N) 33,505 66,205 Seabrook deferral (Note 2L) 8,376 -- Other 101,095 103,726 - --------------------------------------------------------------------------- $2,173,278 $2,221,839 =========================================================================== I. Income Taxes The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the ratemaking treatment of the applicable regulatory commissions. See the Consolidated Statements of Income Taxes for the components of income tax expense. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows: - ----------------------------------------------------------------------------- At December 31, - ----------------------------------------------------------------------------- (Thousands of Dollars) 1997 1996 - ----------------------------------------------------------------------------- Accelerated depreciation and other plant-related differences $ 1,567,597 $ 1,640,068 Net operating loss carryforwards (102,492) (94,149) Regulatory assets -- income tax gross up 395,619 423,363 Other 123,789 100,943 - ----------------------------------------------------------------------------- $ 1,984,513 $ 2,070,225 ============================================================================= At December 31, 1997, PSNH had a net operating loss (NOL) carryforward of approximately $293 million that can be used against PSNH's federal taxable income and which, if unused, expires between the years 2000 and 2006. CL&P had a state of Connecticut NOL carryforward of approximately $131 million that can be used against CL&P and its affiliates' combined Connecticut taxable income and which, if unused, expires in the year 2002. PSNH also had Investment Tax Credit (ITC) carryforwards of $40 million which, if unused, expire between the years 1998 and 2004. For a portion of the carryforward amounts indicated above, the reorganization of PSNH under Chapter 11 of the United States Bankruptcy Code limits the annual amount of PSNH NOL and ITC carryforwards that may be used. Approximately $31 million of the NOL and $9 million of the ITC carryforwards are subject to this limitation. J. Unamortized PSNH Acquisition Costs The unamortized PSNH acquisition costs represent the aggregate value placed by the 1989 rate agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in excess of the net book value of PSNH's non-Seabrook assets, plus the $700 million value assigned to Seabrook by the Rate Agreement, as part of the bankruptcy resolution on June 5, 1992 (Acquisition Date). The Rate Agreement provides for the recovery through rates, with a return, of the unamortized PSNH acquisition costs. The Rate Agreement provides that $425 million of the unamortized PSNH acquisition costs be amortized over the first seven years after PSNH's May 16, 1991 reorganization from bankruptcy (Reorganization Date) with the remaining amount to be amortized over the 20-year period after the Reorganization Date. The unrecovered balance of PSNH acquisition costs at December 31, 1997, was approximately $402.3 million. In accordance with the Rate Agreement, approximately $32.9 million of this amount will be recovered through rates by June 1, 1998, and the remaining amount of approximately $369.4 million will be recovered through rates by 2011. As of December 31, 1997, PSNH has collected approximately $591 million of acquisition costs through rates. K. Recoverable Energy Costs Energy Act: Under the Energy Act, CL&P, PSNH, WMECO and NAEC are assessed for their proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (D&D assessment). The Energy Act requires that regulators treat D&D assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P, PSNH, WMECO and NAEC are currently recovering these costs through rates. As of December 31, 1997, the company's total D&D deferrals were approximately $63.7 million. CL&P: During 1997, CL&P implemented an energy adjustment clause (EAC) under which fuel prices above or below base-rate levels are charged or credited to customers. The EAC replaced CL&P's fuel adjustment and generation utilization adjustment clauses and is designed to reconcile and adjust the difference between actual fuel costs and the fuel revenue collected through base rates on a six-month basis. For the period January 1, 1997 through June 30, 1997, CL&P agreed to a zero EAC rate. For the period July 1, 1997 through December 31, 1997, the DPUC approved an EAC rate through which CL&P recovered approximately $11.5 million of deferred fuel costs. While this proceeding did not include provisions for the recovery of approximately $18 million of costs related to the early closing of CYAPC's nuclear generating unit, it did allow for the recovery of costs, subject to refund, related to the closure of MYAPC's nuclear generating unit. CL&P has appealed the DPUC's ruling related to CYAPC replacement power costs. During December 1997, the DPUC approved an EAC rate for the period January 1, 1998 through June 30, 1998. During this period, CL&P will recover approximately $27.9 million of deferred fuel costs. At December 31, 1997, CL&P's net recoverable energy costs, excluding current net recoverable energy costs, were approximately $104.8 million, which includes approximately $50.1 million of costs related to CL&P's share of the D&D assessment. PSNH: The Rate Agreement includes a comprehensive fuel and purchased power adjustment clause (FPPAC) permitting PSNH to pass through to retail customers, for a ten-year period that began in May 1991, the retail portion of differences between the fuel and purchased power costs assumed in the Rate Agreement and PSNH's actual costs, which include the costs related to the Seabrook Power Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are subject to a prudence review by the New Hampshire Public Utilities Commission (NHPUC). Under the Rate Agreement, the deferred Seabrook return is being deferred by PSNH and subsequently will be billed and collected by PSNH through the FPPAC. PSNH began to defer the amount of these costs on December 1, 1997, and will continue to do so for the period from December 1, 1997 through May 31, 1998. Beginning on June 1, 1998, these costs will be recovered from PSNH customers over a 36-month period. At December 31, 1997, PSNH has deferred approximately $8.4 million of these costs. On February 10, 1998, the NHPUC established a FPPAC rate for the period December 1, 1997 through May 31, 1998. The new FPPAC rate increased customer billings by approximately six percent. This rate continues to defer a substantial portion of these costs. At December 31, 1997, PSNH's net recoverable energy costs, excluding current net recoverable energy costs, were approximately $191.7 million. This amount includes approximately $172.9 million of deferred small power producer costs. WMECO: WMECO has a fuel adjustment clause (FAC) which includes energy costs along with capacity and transmission charges and credits that result from short- term transactions with other utilities and from certain FERC-approved contracts among the NU system's operating companies. The Massachusetts restructuring legislation will effectively eliminate the FAC, effective March 1, 1998. On August 20, 1997, WMECO filed with the DTE a joint motion for approval of a settlement agreement with the Massachusetts Attorney General which allowed WMECO to recover approximately $15.3 million of fuel costs for the period September 1997 through February 1998. At December 31, 1997, WMECO's net recoverable energy costs were approximately $26.3 million, which includes approximately $11.3 million of costs related to WMECO's share of the D&D assessment. For further information on recoverable energy costs, see the MD&A. L. Deferred Costs -- Nuclear Plants As of May 1, 1996, NAEC phased into rates 100 percent of the recoverable portion of its investment in Seabrook 1. This plan is in compliance with SFAS 92, "Regulated Enterprises -- Accounting for Phase-in Plans." From the Acquisition Date through November 1997, NAEC recorded $203.9 million of deferred return on its investment in Seabrook 1. At November 30, 1997, NAEC's utility plant included $84.1 million of deferred return that was transferred as part of the Seabrook plant assets to NAEC on the Acquisition Date. Beginning on December 1, 1997, the deferred return, including the portion transferred to NAEC, is currently being billed through the Seabrook Power Contracts to PSNH and will be fully recovered from customers by May 2001. M. Demand-Side Management (DSM) CL&P's DSM costs are recovered in base rates through a Conservation Adjustment Mechanism. CL&P is allowed to recover DSM costs in excess of costs reflected in base rates over periods ranging from approximately four to ten years. During April 1997, the DPUC approved CL&P's DSM budget of $36 million for 1997. In October 1997, CL&P and other interested parties filed a stipulation with the DPUC requesting that the DPUC approve certain programs and establish a budget level of $32.7 million for 1998 and $28.8 million for 1999. The $52.1 million of DSM costs on CL&P's books as of December 31, 1997, currently being collected, will be fully recovered by 2000. N. CL&P Cogeneration Costs Beginning on July 1, 1996, the deferred cogeneration balance of approximately $86 million is being amortized over a five year period. An additional $9 million of amortization was applied to the deferred balance in 1997, as required under a settlement agreement which CL&P reached with the DPUC. CL&P continues to apply any savings associated with the renegotiation of a certain contract with a cogeneration facility to the deferred balance. Under current expectations, CL&P expects complete amortization of the deferred balance by December 31, 1998. At December 31, 1997, CL&P's deferred cogeneration costs balance was approximately $33.5 million. O. Market Risk-Management Policies The company utilizes market risk-management instruments, including swaps, collars, puts and calls, to hedge well-defined risks associated with variable interest rates and changes in fuel prices. To qualify for hedge treatment, the underlying hedged item must expose the company to risks associated with market fluctuations and the market risk-management instrument used must be designated as a hedge and must reduce the company's exposure to market fluctuations throughout the period. Amounts receivable or payable under fuel-price management instruments are recognized in operating revenues when realized. Amounts receivable or payable under interest-rate management instruments are accrued and offset against interest expense. The company does not use market risk-management instruments for speculative purposes. For further information, see Note 9, "Market Risk Management." P. Spent Nuclear Fuel Disposal Costs Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO and NAEC must pay the United States Department of Energy (DOE) for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. Fees for nuclear fuel burned on or after April 7, 1983, are billed currently to customers and paid to the DOE on a quarterly basis. For nuclear fuel used to generate electricity prior to April 7, 1983 (prior-period fuel), payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the three-month Treasury Bill Yield Rate. At December 31, 1997, fees due to the DOE for the disposal of prior-period fuel were approximately $205.5 million, including interest costs of $123.4 million. The DOE was originally scheduled to begin accepting delivery of spent fuel in 1998. However, delays in identifying a permanent storage site have continually postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. The company has primary responsibility for the interim storage of its spent nuclear fuel. Current capability to store spent fuel at Millstone 1, 2 and Seabrook are estimated to be adequate until the years 2004 for Millstone 1 and 2 and 2010 for Seabrook. Storage facilities for Millstone 3 are expected to be adequate for the projected life of the unit. Meeting spent fuel storage requirements beyond these periods could require new and separate storage facilities, the costs for which have not been determined. In November 1997, the U.S. District Court of Appeals for the D.C. Circuit ruled that the lack of an interim storage facility does not excuse the DOE from meeting its contractual obligation to begin accepting spent nuclear fuel no later than January 31, 1998. Currently, the DOE has not taken the spent nuclear fuel as scheduled and, as a result, may have to pay contract damages. The ultimate outcome of this legal proceeding is uncertain at this time. Q. Cash and Cash Equivalents Cash and cash equivalents includes cash on hand and short-term cash investments which are highly liquid in nature and have original maturities of three months or less. 3. Nuclear Decommissioning Millstone and Seabrook: The NU system's nuclear power plants have service lives that are expected to end during the years 2010 through 2026. Upon retirement, these units must be decommissioned. Current decommissioning studies concluded that complete and immediate dismantlement at retirement continues to be the most viable and economic method of decommissioning the three Millstone units and Seabrook 1. Decommissioning studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology and inflation. The estimated cost of decommissioning Millstone 1 and 2, in year-end 1997 dollars, is $482.6 million and $432.2 million, respectively. The NU system's ownership share of the estimated cost of decommissioning Millstone 3 and Seabrook 1 in year-end 1997 dollars, is $377.4 million and $189.4 million, respectively. The Millstone units and Seabrook 1 decommissioning costs will be increased annually by their respective escalation rates. Nuclear decommissioning costs are accrued over the expected service life of the units and are included in depreciation expense on the Consolidated Statements of Income. Nuclear decommissioning costs amounted to $48.8 million in 1997, $47.8 million in 1996 and $38.9 million in 1995. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Consolidated Balance Sheets. At December 31, 1997 and 1996, the balance in the accumulated reserve for depreciation amounted to $540.8 million and $435.7 million, respectively. CL&P and WMECO have established external decommissioning trusts through a trustee for their portions of the costs of decommissioning Millstone 1, 2 and 3. PSNH makes payments to an independent decommissioning trust for its portion of the costs of decommissioning Millstone 3. CL&P's and NAEC's portions of the cost of decommissioning Seabrook 1 are paid to an independent decommissioning financing fund managed by the state of New Hampshire. Funding of the estimated decommissioning costs assumes levelized collections for the Millstone units and escalated collections for Seabrook 1 and after-tax earnings on the Millstone and Seabrook decommissioning funds of approximately 5.5 percent and 6.5 percent, respectively. As of December 31, 1997, CL&P, PSNH and WMECO collected through rates $277.9 million, $2.6 million and $59.7 million, respectively, toward the future decommissioning costs of their share of the Millstone units, of which $302.6 million has been transferred to external decommissioning trusts. As of December 31, 1997, CL&P and NAEC (including payments made prior to the Acquisition Date by PSNH) paid approximately $2.9 million and $21.1 million, respectively, into Seabrook 1's decommissioning financing fund. Earnings on the decommissioning trusts and financing fund increase the decommissioning trust balance and the accumulated reserve for depreciation. Unrealized gains and losses associated with the decommissioning trusts and financing fund also impact the balance of the trusts and the accumulated reserve for depreciation. Changes in requirements or technology, the timing of funding or dismantling or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. CL&P, PSNH and WMECO attempt to recover sufficient amounts through their allowed rates to cover their expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by regulatory agencies is reflected in rates of the NU system companies. Based on present estimates and assuming its nuclear units operate to the end of their respective license periods, the NU system expects that the decommissioning trusts and financing fund will be substantially funded when the units are retired from service. Millstone 1 has been placed in extended maintenance status while management is reviewing its options with respect to the unit. These include restart, early retirement and other options. Relating to management's consideration of the option to immediately retire Millstone 1 are certain Connecticut state law issues. In its four-year rate review proceeding, the DPUC noted that CL&P may not be able to obtain its remaining investment in Millstone 1 if it were to determine that the unit had been prematurely shut down due to management imprudence. Additionally, there is a Connecticut statute which may limit CL&P's ability to collect future decommissioning charges related to Millstone 1 if Millstone 1 were to be terminated before the end of its expected life. At December 31, 1997, CL&P's net unrecovered Millstone 1 plant costs were $215.7 million and the remaining unrecovered decommissioning costs were approximately $198 million. Yankee Companies: VYNPC owns and operates a nuclear generating unit with a service life that is expected to end in 2012. The NU system's ownership share of estimated costs, in year-end 1997 dollars, of decommissioning this unit is $80.8 million. On August 6, 1997, the board of directors of MYAPC voted unanimously to cease permanently the production of power at its nuclear generating facility (MY). The NU system companies had relied on MY for approximately one percent of their capacity. During November 1997, MYAPC filed an amendment to its power contracts clarifying the obligations of its purchasing utilities following the decision to cease power production. During January 1998, the FERC accepted the amendments and proposed rates, subject to refund. At December 31, 1997, the remaining estimated obligation, including decommissioning, amounted to approximately $867.2 million, of which the NU system's share was approximately $173.4 million. On December 4, 1996, the board of directors of CYAPC voted unanimously to cease permanently the production of power at its nuclear generating plant (CY). During 1996, the NU system companies had relied on CY for approximately three percent of their capacity. During late December 1996, CYAPC filed an amendment to its power contracts clarifying the obligations of its purchasing utilities following the decision to cease power production. On February 27, 1997, the FERC approved an order for hearing which, among other things, accepted CYAPC's contract amendment. The new rates became effective March 1, 1997, subject to refund. At December 31, 1997, the remaining estimated obligation, including decommissioning, amounted to $619.9 million, of which the NU system's share was approximately $303.7 million. YAEC is in the process of decommissioning its nuclear facility. At December 31, 1997, the estimated remaining costs, including decommissioning, amounted to $124.4 million, of which the NU system's share was approximately $47.9 million. Under the terms of the contracts with MYAPC, CYAPC and YAEC, the shareholder- sponsor companies, including CL&P, WMECO and PSNH, are responsible for their proportionate share of the costs of the units, including decommissioning. Management expects that CL&P, PSNH and WMECO each will continue to be allowed to recover these costs from their customers. Accordingly, CL&P, PSNH and WMECO have recognized these costs as regulatory assets, with corresponding obligations. Proposed Accounting: The staff of the SEC has questioned certain current accounting practices of the electric utility industry, including NU, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating units in the financial statements. In response to these questions, the FASB has agreed to review the accounting for closure and removal costs, including decommissioning. If current electric utility industry accounting practices for nuclear power plant decommissioning are changed, the annual provision for decommissioning could increase relative to 1997, and the estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation), with recognition of an increase in the cost of the related nuclear power plant. Management believes that the operating companies each will continue to be allowed to recover decommissioning costs through rates. 4. Short-Term Debt Limits: The amount of short-term borrowings that may be incurred by the NU system's utility companies is subject to periodic approval by either the SEC under the 1935 Act or by their respective state regulators. SEC authorization allowed CL&P, WMECO and NAEC, as of January 1, 1998, to incur total short-term borrowings up to a maximum of $375 million, $150 million and $60 million, respectively. In addition, the charter of WMECO contains a provision which restricts the total amount of unsecured debt that it may borrow at any one time. As of January 1, 1998, this charter provision allowed WMECO to incur unsecured borrowings, whether short-term or long-term, up to a maximum of approximately $114 million. PSNH was authorized under a waiver from the NHPUC to incur short- term borrowings up to a maximum of $125 million effective May 1997. Credit Agreements: In May 1997, because of the potential for NU and CL&P to violate their various financial ratio tests, NU amended the three-year revolving credit agreement (Credit Agreement) with a group of 12 banks. Under the amended Credit Agreement, CL&P and WMECO are able to borrow, subject to the availability of first mortgage bond collateral, up to $313.75 million and $150 million, respectively. At December 31, 1997, CL&P and WMECO have issued first mortgage bonds to enable borrowings under this facility up to a maximum of $225 million and $90 million, respectively. NU, which cannot issue first mortgage bonds, will be able to borrow up to $50 million if NU consolidated, CL&P and WMECO each meet certain interest coverage tests for two consecutive quarters. In addition, CL&P and WMECO each must meet certain minimum quarterly financial ratios to access the Credit Agreement. Both CL&P and WMECO satisfied these tests for the quarter ending December 31, 1997. The overall limit for all of the borrowing system companies under the entire Credit Agreement is $313.75 million. The companies are obligated to pay a facility fee of .50 percent per annum of each bank's total commitment under this Credit Agreement, which will expire in November 1999. At December 31, 1997 and 1996, there were $50 million and $27.5 million, respectively, in borrowings under this Credit Agreement. In February 1998, because of borrowing restrictions on NU in the amended Credit Agreement, NU entered into a separate $25 million 364-day revolving credit facility (Credit Facility) with one bank. NU is obligated to pay a facility fee of .625 percent per annum on the unused commitment. In addition to the Credit Agreement and Credit Facility, NU, CL&P, WMECO, HWP and The Rocky River Realty Company (RRR) have various revolving credit lines through separate bilateral credit agreements. Under this facility, four banks maintain commitments to the respective companies totaling $56.25 million. NU, CL&P and WMECO may borrow up to the aggregate $56.25 million, whereas HWP and RRR may borrow up to their SEC or board authorized short-term debt limit of $5 million and $22 million, respectively. Under the terms of this facility, the companies are obligated to pay a facility fee of .15 percent per annum of each bank's total commitment. These commitments will expire in December 1998. At December 31, 1997 and 1996, there were no borrowings and $11.3 million in borrowings, respectively, under this facility. PSNH has a $125 million revolving credit agreement that will expire in April 1999. The revolving credit agreement is with a group of 16 banks. PSNH is obligated to pay a facility fee of .50 percent per annum on the commitment of $125 million. At December 31, 1997 and 1996, there were no borrowings under the facility. Under the credit facilities discussed above, with the exception of the $25 million NU Credit Facility, the NU system companies may borrow funds on a short- term revolving basis under their respective agreements, using either fixed-rate loans or standby loans. Fixed rates are set using competitive bidding. Standby loans are based upon several alternative variable rates. Loans advanced under the $25 million NU Credit Facility are on a standby basis only. The weighted average annual interest rate on the NU system companies' notes payable to banks outstanding on December 31, 1997 and 1996 was 6.95 percent and 8.3 percent, respectively. Maturities of short-term debt obligations were for periods of three months or less. For further information on short-term debt, including the ability to access these agreements, see the MD&A. 5. Leases CL&P and WMECO may finance up to $400 million of nuclear fuel for Millstone 1 and 2 and their respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement which is scheduled to expire July 31, 1998. The NBFT capital lease agreement, which was amended in February 1998, requires CL&P and WMECO to secure their obligation to repay the NBFT with up to $90 million of first mortgage bonds. CL&P and WMECO will issue these bonds by May 1998. CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel consumed in the reactors based on a units-of-production method at rates which reflect estimated kilowatt hours of energy provided plus financing costs associated with the fuel in the reactors. Upon permanent discharge from the reactors, ownership of the nuclear fuel transfers to CL&P and WMECO. The NU system companies also have entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, gas turbines, nuclear control room simulators and office space. The provisions of these lease agreements generally provide for renewal options. Capital lease rental payments charged to operating expense were $19.0 million in 1997, $28.2 million in 1996 and $75.9 million in 1995. Interest included in capital lease rental payments was $13.6 million in 1997, $14.1 million in 1996 and $15.0 million in 1995. Operating lease rental payments charged to expense were $17.3 million in 1997, $18.3 million in 1996 and $20.9 million in 1995. Future minimum rental payments, excluding executory costs such as property taxes, state use taxes, insurance and maintenance, under long-term noncancelable leases, as of December 31, 1997, are: - --------------------------------------------------------------------------- (Thousands of Dollars) - --------------------------------------------------------------------------- Capital Operating Year Leases Leases - --------------------------------------------------------------------------- 1998 $181,000 $ 25,800 1999 8,500 23,200 2000 7,900 21,000 2001 5,800 16,500 2002 3,200 8,000 After 2002 54,900 26,600 - --------------------------------------------------------------------------- Future minimum lease payments 261,300 $121,100 ======== Less amount representing interest 53,300 -------- Present value of future minimum lease payments $208,000 ======== 6. Employee Benefits A. Pension Benefits The NU system's subsidiaries participate in a uniform noncontributory defined benefit retirement plan covering all regular NU system employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. Total pension (credit)/cost, part of which was (credited)/charged to utility plant, approximated $(22.5) million in 1997, $9.1 million in 1996 and $0.4 million in 1995. Pension (credit)/costs for 1997, 1996 and 1995 included approximately $(2.6) million, $7.8 million and $6.8 million, respectively, related to workforce reduction programs. Currently, the subsidiaries annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code. Pension costs are determined using market-related values of pension assets. Pension assets are invested primarily in domestic and international equity securities and bonds. The components of net pension (credit)/cost are: - ---------------------------------------------------------------------------- For the Years Ended December 31, - ---------------------------------------------------------------------------- (Thousands of Dollars) 1997 1996 1995 - ---------------------------------------------------------------------------- Service cost $ 32,298 $ 43,206 $ 35,771 Interest cost 98,621 94,722 89,351 Return on plan assets (337,198) (232,604) (310,997) Net amortization 183,752 103,745 186,310 - ----------------------------------------------------------------------------- Net pension (credit)/cost $ (22,527) $ 9,069 $ 435 ============================================================================= For calculating pension costs, the following assumptions were used: - ----------------------------------------------------------------------------- For the Years Ended December 31, - ----------------------------------------------------------------------------- 1997 1996 1995 - ----------------------------------------------------------------------------- Discount rate 7.75% 7.50% 8.25% Expected long-term rate of return 9.25 8.75 8.50 Compensation/progression rate 4.75 4.75 5.00 ============================================================================= The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: - ---------------------------------------------------------------------------- At December 31, - ---------------------------------------------------------------------------- (Thousands of Dollars) 1997 1996 - ---------------------------------------------------------------------------- Accumulated benefit obligation including vested benefits at December 31, 1997 and 1996 of $(1,003,157,000) and $(943,696,000), respectively $(1,106,850) $(1,037,908) - ---------------------------------------------------------------------------- Projected benefit obligation $(1,392,833) $(1,321,146) Market value of plan assets 1,919,414 1,660,404 - ----------------------------------------------------------------------------- Market value in excess of projected benefit obligation 526,581 339,258 Unrecognized transition amount (10,562) (12,105) Unrecognized prior service cost 29,711 31,802 Unrecognized net gain (622,916) (458,654) - ---------------------------------------------------------------------------- Accrued pension liability $ (77,186) $ (99,699) ============================================================================= The following actuarial assumptions were used in calculating the plan's year-end funded status: - ---------------------------------------------------------------------------- At December 31, - ---------------------------------------------------------------------------- 1997 1996 - ----------------------------------------------------------------------------- Discount rate 7.25% 7.75% Compensation/progression rate 4.25 4.75 ============================================================================= B. Postretirement Benefits Other Than Pensions The NU system's subsidiaries provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (referred to as SFAS 106 benefits). These benefits are available for employees retiring from the NU system who have met specified service requirements. For current employees and certain retirees, the total SFAS 106 benefit is limited to two times the 1993 per-retiree health care cost. The SFAS 106 obligation has been calculated based on this assumption. Total SFAS 106 benefit costs, part of which were deferred or charged to utility plant, approximated $28.3 million in 1997, $39.2 million in 1996 and $44.1 million in 1995. NU's subsidiaries are funding SFAS 106 postretirement costs through external trusts. The subsidiaries are funding, on an annual basis, amounts that have been rate-recovered and which also are tax deductible under the Internal Revenue Code. The trust assets are invested primarily in equity securities and bonds. The components of health care and life insurance cost are: - ----------------------------------------------------------------------------- For the Years Ended December 31, - ----------------------------------------------------------------------------- (Thousands of Dollars) 1997 1996 1995 - ----------------------------------------------------------------------------- Service cost $ 5,746 $ 7,457 $ 7,137 Interest cost 20,556 22,698 24,693 Return on plan assets (21,452) (9,330) (7,812) Amortization of unrecognized transition obligation 15,134 15,134 15,134 Other amortization, net 8,327 3,194 4,924 - ---------------------------------------------------------------------------- Net health care and life insurance cost $ 28,311 $ 39,153 $ 44,076 ============================================================================ For calculating SFAS 106 benefit costs, the following assumptions were used: - ----------------------------------------------------------------------------- For the Years Ended December 31, - ----------------------------------------------------------------------------- 1997 1996 1995 - ----------------------------------------------------------------------------- Discount rate 7.75% 7.50% 8.00% Long-term rate of return -- Health assets, net of tax 6.00 5.25 5.00 Life assets 9.25 8.75 8.50 ============================================================================= The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: - ----------------------------------------------------------------------------- At December 31, - ---------------------------------------------------------------------------- (Thousands of Dollars) 1997 1996 - ----------------------------------------------------------------------------- Accumulated postretirement benefit obligation of: Retirees $(214,624) $(226,774) Fully eligible active employees (529) (323) Active employees not eligible to retire (70,806) (78,985) - ---------------------------------------------------------------------------- Total accumulated postretirement benefit obligation (285,959) (306,082) Market value of plan assets 129,434 105,086 - ---------------------------------------------------------------------------- Accumulated postretirement benefit obligation in excess of plan assets (156,525) (200,996) Unrecognized transition obligation 227,015 242,149 Unrecognized net gain (70,391) (41,457) - ---------------------------------------------------------------------------- Prepaid/(accrued) postretirement benefit obligation $ 99 $ (304) ============================================================================ The following actuarial assumptions were used in calculating the plan's year-end funded status: - ----------------------------------------------------------------------------- At December 31, - ----------------------------------------------------------------------------- 1997 1996 - ---------------------------------------------------------------------------- Discount rate 7.25% 7.75% Health care cost trend rate (a) 5.76 7.23 ============================================================================= (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 4.40 percent by 2001. The effect of increasing the assumed health care cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1997, by $16.1 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $1.3 million. The trust holding the health plan assets is subject to federal income taxes at a 39.6 percent tax rate. CL&P, PSNH and WMECO currently are recovering SFAS 106 costs through rates. C. 401(k) Savings Plan NU maintains a 401(k) Savings Plan for substantially all NU system employees. This savings plan provides for employee contributions up to specified limits. The company matches, with company stock, employee contributions up to a maximum of three percent of eligible compensation. The matching contributions made by the company were $12.0 million for 1997, $11.8 million for 1996 and $12.1 million for 1995. D. ESOP NU maintains an ESOP for purposes of allocating shares to employees participating in the NU system's 401(k) plan. Under this arrangement, NU issued unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of which were lent to the ESOP trust for purchase of approximately 10.8 million newly issued NU common shares (ESOP shares). NU makes principal and interest payments on the ESOP notes at the same rate that ESOP shares are allocated to employees. In 1997 and 1996, the ESOP trust issued approximately 948,000 and 953,000 of NU common shares, respectively, to satisfy plan obligations to employees totaling approximately $21.9 million and $22.1 million, respectively. These costs were charged to the 401(k) plan. As of December 31, 1997 and 1996, the total allocated ESOP shares were 4,140,751 and 3,192,620, respectively, and total unallocated ESOP shares were 6,659,434 and 7,607,565, respectively. The fair market value of unallocated ESOP shares as of December 31, 1997 and 1996 was approximately $78.7 million and $99.8 million, respectively. During 1997, the ESOP trust used approximately $3 million in dividends and $41 million in contributions from NU to meet principal and interest payments on ESOP notes. During March 1997, NU's Board of Trustees suspended the quarterly dividend on NU's common shares indefinitely, beginning with the second quarter of 1997. Future principal and interest payments on ESOP notes will be fully supported by contributions from NU until the dividend is restored. E. Stock-Based Compensation During 1997, certain key officers of the company were awarded nonvested stock grants, totaling 25,700 shares, under which the officers pay nothing to receive these shares. These officers must stay in employment of the company for a specified period to receive the shares. During 1996, the same key officers of the company were awarded nonvested stock grants, for a total of approximately 43,000 shares, for which again no payment was required. Under the 1996 programs, certain shares became vested immediately with certain restrictions and others became vested upon the meeting of specified performance goals within a limited time period. Dividends accruing on the shares of each award are reinvested in additional shares subject to the same provisions and restrictions. Under these programs, approximately 3,400 shares were vested at December 31, 1997, and December 31, 1996. During August 1997, the company's Board of Trustees approved the granting of 500,000 stock options to the new Chief Executive Officer to purchase common shares of NU common stock. The exercise price of these options is $9.625 per share, which equaled the fair value of the company's common stock at the date of grant. The exercise period for the options granted is ten years from the date of grant, with vesting from the date of grant as follows: 50 percent after two years, 75 percent after three years and 100 percent after four years. The company accounts for its nonvested stock grants and stock options using the intrinsic-value based method in accordance with Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," (APB 25) under which approximately $238 thousand and $136 thousand of compensation costs were recognized in 1997 and 1996, respectively, for the nonvested stock grants. No compensation costs have been recognized for the stock options award as the exercise price was equal to the market value of the stock on the date of grant. In October 1995 the FASB issued SFAS 123, "Accounting for Stock-Based Compensation," which defines a fair-value based method of accounting for stock- based compensation. SFAS 123 allows companies to continue accounting for stock- based compensation using APB 25 but requires pro forma net income and earnings per share disclosures as if the fair-value based method of accounting under SFAS 123 had been used. Had compensation costs of the options award been determined under the fair value alternative method as stated in SFAS 123, the company's pro forma net loss for the year ended December 31, 1997, would have been increased by approximately $73 thousand. The resulting pro forma impact on the company's loss per share for the year was not material. The fair value of the options as of the date of grant was determined using the Black-Scholes option pricing model with the following assumptions: risk-free interest rate of 6.41 percent, expected life of 10.0 years, expected volatility of 31.89 percent and a dividend yield of 7.42 percent. 7. Sale of Customer Receivables and Accrued Utility Revenues During 1996, CL&P and WMECO entered into agreements to sell up to $200 million and $40 million, respectively, of undivided ownership interests in eligible customer receivables and accrued utility revenues (receivables). The FASB issued SFAS 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," in June 1996. SFAS 125 became effective on January 1, 1997, and establishes, in part, criteria for concluding whether a transfer of financial assets in exchange for consideration should be accounted for as a sale or as a secured borrowing. By October 31, 1997, both CL&P and WMECO had restructured their respective sales agreements to comply with the conditions of SFAS 125 and account for transactions occurring under these programs as sales of assets. CL&P and WMECO have each established a special purpose, wholly owned subsidiary whose business consists of the purchase and resale of receivables. For receivables sold, both CL&P and WMECO have retained collection responsibilities as agent for the purchaser under each company's respective agreements. As collections reduce previously sold receivables, new receivables may be sold. At December 31, 1997, approximately $70 million and $20 million of receivables had been sold to third-party purchasers by CL&P and WMECO, respectively, through the use of each company's special purpose, wholly owned subsidiary, CL&P Receivables Corporation (CRC) and WMECO Receivables Corporation (WRC). All receivables transferred to both CRC and WRC are assets owned by CRC and WRC and are not available to pay CL&P's or WMECO's creditors. For CRC's and WRC's respective sales agreements with the third-party purchasers, the receivables were sold with limited recourse. Both CRC's and WRC's respective sales agreements provide for a formula-based loss reserve in which additional receivables may be assigned to the third-party purchasers for costs such as bad debt. The third-party purchasers absorb the excess amount in the event that actual loss experience exceeds the loss reserve. At December 31, 1997, approximately $7.2 million and $3.0 million of assets had been designated as collateral by CRC and WRC, respectively. These amounts represent the formula- based amount of credit exposure at December 31, 1997. Historical losses for bad debt for both CL&P and WMECO have been substantially less. During December 1997, Moody's Investors Service downgraded the rating on WMECO's first mortgage bonds. This downgrade brought WMECO's bond ratings to a level at which the sponsor of WMECO's accounts receivable program can take various actions, in its discretion, which would have the practical effect of limiting WMECO's ability to utilize the facility. To date, the sponsor has not notified WMECO that it will elect to exercise those rights, and the program is functioning in its normal mode. The WMECO accounts receivable program could be terminated if WMECO's first mortgage bond credit ratings experience one more level of downgrade. CL&P's accounts receivable program could be terminated if its senior secured debt is downgraded two more steps from its current ratings. Concentrations of credit risk to the respective purchasers under each company's agreements with respect to the receivables are limited due to CL&P's and WMECO's diverse customer base within their respective service territories. For additional information on accounts receivable programs and CL&P's and WMECO's ability to utilize these programs, see the MD&A. 8. Commitments and Contingencies A. Restructuring and Rate Matters New Hampshire: The 1996 restructuring legislation that the NHPUC is charged with implementing provides that the NHPUC may not adopt a restructuring plan that imposes a severe financial hardship on a utility. Management believes that PSNH is entitled to full recovery of its prudently incurred costs, including regulatory assets and other strandable costs. It bases this belief both on the general nature of public utility industry cost-of-service based regulation and the specific circumstances of the resolution of PSNH's previous bankruptcy proceedings and its acquisition by NU, including the recoveries provided by the Rate Agreement and related agreements. On February 28, 1997, the NHPUC issued its decision related to restructuring the state's electric utility industry and setting interim stranded cost charges for PSNH pursuant to legislation enacted in New Hampshire in 1996. In the decision, the NHPUC announced a departure from cost-based ratemaking and instead adopted a market-priced approach to ratemaking and stranded cost recovery. Accordingly, unless the NHPUC modifies its position or the litigation described below results in necessary modifications to the final plan which leads management to conclude that the ratemaking approach utilized in the NHPUC's restructuring decision will not go into effect, PSNH no longer will be subject to the provisions of SFAS 71. That would result in PSNH writing off from its balance sheet substantially all of its regulatory assets. The amount of the potential write-off triggered by the order is currently estimated at over $400 million, after taxes. PSNH does not believe that under the decision, it would be required to recognize any additional loss resulting from the impairment of the value of its other long- lived assets under the provisions of SFAS 121. On March 3, 1997, PSNH, NU, NAEC and NUSCO filed for a temporary restraining order, preliminary and permanent injunctive relief and for declaratory judgment in the United States District Court for New Hampshire (District Court). The case was subsequently transferred to Rhode Island. On March 10, 1997, the Chief Judge of the Rhode Island federal court issued a temporary restraining order which stayed the NHPUC's February 28, 1997, decision to the extent it established a rate-setting methodology that is not designed to recover PSNH's costs of providing service and would require PSNH to write off any regulatory assets. During 1997, a mediation process ended without a resolution. The District Court had suspended the procedural schedule associated with this court proceeding pending the resolution of appeals of certain preliminary rulings by the U.S. Circuit Court of Appeals for the First Circuit (First Circuit). On February 3, 1998, the First Circuit denied the appeals taken by would-be intervenors in PSNH's federal court proceeding concerning the NHPUC's final plan on restructuring. The First Circuit affirmed a previous court decision stating that the opposing interests in this case were adequately represented by the NHPUC or by PSNH. As a result of this decision, the proceedings in the District Court may resume. On February 17, 1998, the NHPUC filed a petition for rehearing with the First Circuit. The temporary restraining order issued by the District Court in March 1997 will remain in effect until further orders by either court. During 1997, the NHPUC reopened its proceeding to reconsider certain limited matters in its restructuring orders. The scope of the PSNH-specific rehearing proceedings included alternative rate-setting methodologies proposed by the intervenors; to decide the appropriate methodology to be used to determine PSNH's interim stranded costs; and to set PSNH's interim stranded cost charges utilizing the determined methodology. In testimony filed with the NHPUC in November 1997, PSNH proposed a new methodology to quantify its strandable costs. Under this proposal, PSNH would divest all owned generation and purchased-power obligations via auction. To the extent that the auction fails to produce sufficient revenues to cover the net book value of owned generation and contractual payment obligations of purchased power, the difference would be recovered from customers through a non-bypassable distribution charge. The new proposal also relies upon securitization of certain assets to further reduce rates. On December 15, 1997, the NHPUC officially announced that industry restructuring would not take place on January 1, 1998. Management believes that industry restructuring will not take place in New Hampshire until the courts resolve the issues brought before them, or the parties involved reach a settlement. PSNH and NAEC are parties to a variety of financing agreements providing that the credit thereunder can be terminated or accelerated if they do not maintain specified minimum ratios of common equity to capitalization (as defined in each agreement). In addition, PSNH and NAEC are parties to a variety of financing agreements providing in effect that the credit thereunder can be terminated or accelerated if there are actions taken, either by PSNH or NAEC or by the state of New Hampshire, that deprive PSNH and/or NAEC of the benefits of the Rate Agreement and/or the Seabrook Power Contracts. If the NHPUC's February 28, 1997 decision were to become effective, it would, unless PSNH and NAEC receive waivers from their respective lenders, result in (i) write-offs that would cause PSNH's common equity to fall below the contractual minimums, (ii) reductions in income that would cause PSNH's income to fall below the contractual minimums, (iii) potential violation of the contractual provisions with respect to actions depriving PSNH and NAEC of the benefits of the Rate Agreement and (iv) the potential for cross defaults to other PSNH and NAEC financing documents. Substantially all of PSNH's and NAEC's debt obligations would be affected. If these events transpired and if the creditors holding PSNH and NAEC debt obligations decide to exercise their rights to demand payment, then either creditors or PSNH and NAEC could initiate proceedings under Chapter 11 of the bankruptcy laws. As a result of the NHPUC decision and the potential consequences discussed above, the reports of our auditors on the individual financial statements of PSNH and NAEC contain explanatory paragraphs. Those explanatory paragraphs indicate that a substantial doubt exists currently about the ability of PSNH and NAEC to continue as going concerns. The accounts of PSNH and NAEC are included in the accompanying consolidated financial statements on the basis of a going concern. While the effect of the implementation of that decision would have a material adverse impact on NU's financial position, results of operations and cash flows, it would not in and of itself result in defaults under borrowing or other financial agreements of NU or its other subsidiaries. On May 2, 1997, PSNH made a rate filing with the NHPUC. For information regarding this rate proceeding, see the MD&A. Massachusetts: During November 1997, the state of Massachusetts enacted a comprehensive electric utility industry restructuring bill (legislation). On December 31, 1997, WMECO filed its restructuring plan with the DTE, as required by the legislation. The WMECO restructuring plan describes the process by which WMECO will, beginning March 1, 1998, initiate a ten percent rate reduction for all customer rate classes and allow customers to choose their energy supplier. As part of the plan, the DTE authorized recovery of certain strandable, above- market costs (strandable costs). The legislation gives the DTE the authority to determine the amount of strandable costs that will be eligible for recovery by utilities. Costs which will qualify as strandable costs and be eligible for recovery include, but are not limited to, certain above-market costs associated with generating facilities, costs associated with long-term commitments to purchase power at above-market prices from small power producers and nonutility generators, and regulatory assets and associated liabilities related to the generation portion of WMECO's business. Under the statute, if a distribution company claims that it is unable to meet a price reduction of ten percent initially and 15 percent by September 1, 1999, the distribution company may so state to the DTE and the DTE is provided with the authority to "explore all possible mechanisms and options within the limits of the constitution" to achieve the mandated rate reductions. The statute indicates that allowing a substitute company to provide standard offer service is one option that can be considered by the DTE. The costs of transitioning to competition will be mitigated through several steps, including divesting WMECO's nonnuclear generating assets at an auction to be held as soon as June 1998, and securitization of approximately $500 million in strandable costs by September 30, 1998. NU presently expects to participate, through a competitive affiliate, in the competitive bid process for WMECO's generation resources. Any net proceeds in excess of book value received from the divestiture of these units will be used to mitigate strandable costs. As required by the legislation, WMECO will continue to operate and maintain its transmission and local distribution network and deliver electricity to all customers. As noted above, the legislation has authorized Massachusetts utilities to finance a portion of the strandable costs through securitization, using rate reduction bonds. A separate transition charge will be collected over the life of the bonds to recover principal, interest and issuance costs. WMECO's ability to recover its strandable costs will depend on several factors, which include, but are not limited to, continuous recovery of the costs over the transitional period supported by the legislation, the aggregate amount of strandable costs which the company will be allowed to recover and the market price of electricity. Management believes that the company will recover its strandable costs. However, a change in one or more of these factors could affect the recovery of strandable costs and may result in a loss to the company. Connecticut: Although CL&P continues to operate under cost-of-service based regulation, legislative restructuring initiatives during 1997 and 1998 in its jurisdiction has created some uncertainty with respect to future rates and the recovery of strandable investments and certain future costs such as purchase power obligations. Management is unable to predict the ultimate outcome of restructuring initiatives, however, it continues to believe that it is probable that CL&P will fully recover its prudently incurred costs, including regulatory assets and strandable investments based on the general nature of public utility cost-of-service regulation. For further information on restructuring, see Note 2H, "Summary of Significant Accounting Policies -- Regulatory Accounting and Assets" and the MD&A. The DPUC is required to review a utility's rates every four years if there has not been a rate proceeding during such period. The DPUC has conducted such a review. For information regarding this review and other rate matters, see the MD&A. FERC Rate Proceedings: For information regarding the FERC rate proceedings for CYAPC and MYAPC, see Note 3, "Nuclear Decommissioning." B. Nuclear Performance Millstone: The three Millstone units are managed by NNECO. Millstone 1, 2 and 3 have been out of service since November 4, 1995, February 21, 1996, and March 30, 1996, respectively, and are on the Nuclear Regulatory Commission's (NRC) watch list. The company has restructured its nuclear organization and is currently implementing comprehensive plans to restart the units. Subsequent to its January 31, 1996, announcement that Millstone had been placed on its watch list, the NRC stated that the units cannot return to service until independent, third-party verification teams have reviewed the actions taken to improve the design, configuration and employee concerns issues that prompted the NRC to place the units on its watch list. The actual date of the return to service for each of the units is dependent upon the completion of independent inspections and reviews by the NRC and a vote by the NRC commissioners. NU hopes to return Millstone 3 to service in early spring of 1998 and Millstone 2 three to four months after Millstone 3. Millstone 1 is currently in extended maintenance status. Management cannot predict when the NRC will allow any of the Millstone units to return to service and thus cannot precisely estimate the total replacement power costs the companies ultimately will incur. Replacement power costs incurred by NU attributable to the Millstone outages averaged approximately $28 million per month during 1997, and for 1998 are projected to average approximately $9 million per month for Millstone 3, $9 million per month for Millstone 2 and $6 million per month for Millstone 1 while the plants remain out of service. CL&P, WMECO and PSNH will continue to expense their replacement power costs in 1998. Based on the current estimates of expenditures and restart dates, management believes the NU system has sufficient resources to fund the restoration of the Millstone units and related replacement power costs. If the return to service of Millstone 3 or 2 is delayed substantially beyond the present restart estimates, if some financing facilities become unavailable because of difficulties in meeting borrowing conditions or renegotiating extensions, if CL&P and WMECO encounter additional significant costs or if any other significant deviations from management's assumptions occur, CL&P and WMECO could be unable to meet their cash requirements. In those circumstances, management would take even more stringent actions to reduce costs and cash outflows and attempt to obtain additional sources of funds. The availability of these funds would be dependent upon general market conditions and CL&P's and WMECO's respective credit and financial conditions at that time. For information regarding Millstone restart costs, see the MD&A. For information concerning the ability of CL&P and WMECO to access their borrowing facilities, see the MD&A. Litigation: Several class-action lawsuits have been filed against the company and certain present and former officers and employees of NU in connection with the company's nuclear operations. Management cannot estimate the potential outcome of these suits, but believes these suits are without merit and intends to defend itself vigorously in all these actions. CL&P and WMECO, through NNECO as agent, operate Millstone 3 at cost, and without profit, under a sharing agreement that obligates them to utilize good utility operating practice and requires the joint owners to share the risk of employee negligence and other risks of operation and maintenance pro-rata in accordance with their ownership shares. This agreement also provides that CL&P and WMECO would be liable only for damages to the non-NU owners for a deliberate violation of the agreement pursuant to authorized corporate action. On August 7, 1997, the non-NU owners of Millstone 3 filed demands for arbitration with CL&P and WMECO as well as lawsuits in Massachusetts Superior Court against NU and its current and former trustees. The non-NU owners raise a number of contract, tort and statutory claims arising out of the operation of Millstone 3. The arbitrations and lawsuits seek to recover compensatory damages, punitive damages, treble damages and attorneys' fees. Owners representing approximately two-thirds of the non-NU interests in Millstone 3 claimed compensatory damages in excess of $200 million. In addition, one of the lawsuits seeks to restrain NU from disposing of its shares of the stock of WMECO and HWP, pending the outcome of the lawsuit. Management cannot estimate the potential outcome of these suits but believes there is no legal basis for the claims and intends to defend against them vigorously. To date, no reserves have been established for this litigation. At December 31, 1997, the costs related to this litigation were estimated to be approximately $100 million for incremental O&M costs and approximately $100 million for replacement power costs. These costs are likely to increase as long as Millstone 3 remains out of service. The Connecticut Municipal Electric Energy Cooperative (CMEEC) and CL&P have been negotiating since May 1996 over issues related to the operation of Millstone 1 and 2. CMEEC has failed to make payments on its accrued obligations since October 1996, claiming that CL&P materially breached its contractual obligations. CL&P has denied the allegations and requested payment. The matter has gone to arbitration which has been scheduled for July 1998. CL&P has filed an application with the Connecticut Superior Court in Hartford requesting the court to grant interim relief to CL&P. CL&P has asked the court to enforce the contract provisions by ordering CMEEC to pay the outstanding obligations under the contract (approximately $25 million) and to continue making payments (approximately $1.8 million per month) during the arbitration process. On December 9, 1997, the Superior Court judge issued a decision denying CL&P's request for an interim payment order. Management cannot predict the outcome of this litigation and has taken steps to assert its legal rights. CL&P has requested reargument, in order to present evidence, and has requested that the Connecticut Superior Court vacate its order. CL&P is prepared to appeal to a higher court, if necessary, after the reargument. C. Environmental Matters The NU system is subject to regulation by federal, state and local authorities with respect to air and water quality, the handling and disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. The NU system has an active environmental auditing and training program and believes that it is in substantial compliance with current environmental laws and regulations. However, the NU system is subject to certain pending enforcement actions and governmental investigations in the environmental area. Management cannot predict the outcome of these enforcement actions and investigations. Environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations and other facilities. Changing environmental requirements could also require extensive and costly modifications to the NU system's existing generating units and transmission and distribution systems, and could raise operating costs significantly. As a result, the NU system may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation and transmission of electricity and the storage, transportation and disposal of byproducts and wastes. The NU system also may encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. The cumulative long-term cost impact of increasingly stringent environmental requirements cannot be estimated accurately. The NU system has recorded a liability based upon currently available information for what it believes are its estimated environmental remediation costs that the NU system's subsidiaries expect to incur for waste disposal sites. In most cases, additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation and the possible effects of technological changes. At December 31, 1997, the net liability recorded by the NU system for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $16.2 million, which management has determined to be the most probable amount within the range of $16.2 million to $28.0 million. During 1997, NU adopted Statement of Position 96-1, "Environmental Remediation Liabilities" (SOP). The principal objective of the SOP is to improve the manner in which existing authoritative accounting literature is applied by entities to specific situations of recognizing, measuring and disclosing environmental remediation liabilities. The adoption of the SOP resulted in an increase of approximately $1.5 million to NU's environmental reserve in 1997. The NU system cannot estimate the potential liability for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws and regulatory practices, management does not believe the matters disclosed above will have a material effect on the NU system's financial position or future results of operations. D. Nuclear Insurance Contingencies Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities in the country covered by the federal government's third- party liability indemnification program, an owner of a nuclear unit could be assessed in proportion to its ownership interest in each of its nuclear units up to $75.5 million. Payments of this assessment would be limited to $10.0 million in any one year per nuclear incident based upon the owner's pro rata ownership interest in each of its nuclear units. In addition, the owner would be subject to an additional five percent or $3.8 million, in proportion to its ownership interests in each of its nuclear units, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection. Based upon its ownership interests in Millstone 1, 2 and 3 and in Seabrook 1, the NU system's maximum liability, including any additional assessments, would be $244.2 million per incident, of which payments would be limited to $30.8 million per year. In addition, through power purchase contracts with MYAPC, VYNPC and CYAPC, the NU system would be responsible for up to an additional $67.4 million per incident, of which payments would be limited to $8.5 million per year. Insurance has been purchased to cover the primary cost of repair, replacement or decontamination of utility property resulting from insured occurrences. The NU system is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessment against the system with respect to losses arising during the current policy year is approximately $17.1 million under the primary property insurance program. Insurance has been purchased to cover certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement or decontamination or premature decommissioning of utility property resulting from insured occurrences. The NU system is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessments against the NU system with respect to losses arising during current policy years are approximately $13.8 million under the replacement power policies and $24.6 million under the excess property damage, decontamination and decommissioning policies. The cost of a nuclear incident could exceed available insurance proceeds. Insurance has been purchased aggregating $200 million on an industry basis for coverage of worker claims. All participating reactor operators insured under this coverage are subject to retrospective assessments of $3 million per reactor. The maximum potential assessment against the NU system with respect to losses arising during the current policy period is approximately $13.0 million. Effective January 1, 1998, a new worker policy was purchased which is not subject to retrospective assessments. E. Construction Program The construction program is subject to periodic review and revision by management. The NU system companies currently forecast construction expenditures of approximately $2.0 billion for the years 1998-2002, including $267 million for 1998. In addition, the NU system companies estimate that nuclear fuel requirements, including nuclear fuel financed through the NBFT, will be approximately $360.7 million for the years 1998-2002, including $60.6 million for 1998. See Note 5, "Leases," for additional information about the financing of nuclear fuel. F. Long-Term Contractual Arrangements Yankee Companies: The NU system companies rely on VY for approximately 1.7 percent of their capacity under long-term contracts. Under the terms of their agreements, the NU system companies pay their ownership (or entitlement) shares of costs, which include depreciation, O&M expenses, taxes, the estimated cost of decommissioning and a return on invested capital. These costs are recorded as purchased power expense and are recovered through the companies' rates. The total cost of purchases under contracts with VYNPC amounted to $24.2 million in 1997, $25.5 million in 1996 and $25.3 million in 1995. The other Yankee generating facilities, MY, CY and Yankee Rowe, were permanently shut down as of August 6, 1997, December 4, 1996, and February 26, 1992, respectively. See Note 1E, "Summary of Significant Accounting Policies -- Investments and Jointly Owned Electric Utility Plant," for further information on the Yankee companies, and Note 3, "Nuclear Decommissioning," regarding the related decommissioning obligations. Nonutility Generators: CL&P, PSNH and WMECO have entered into various arrangements for the purchase of capacity and energy from nonutiltiy generators (NUGs). These arrangements have terms from 10 to 30 years, currently expiring in the years 1998 through 2028, and require the companies to purchase energy at specified prices or formula rates. For the twelve month period ending December 31, 1997, approximately 14 percent of NU system electricity requirements was met by NUGs. The total cost of purchases under these arrangements amounted to $447.6 million in 1997, $441.6 million in 1996 and $434.7 million in 1995. These costs may be deferred for eventual recovery through rates. New Hampshire Electric Cooperative: PSNH entered into a buy-back agreement to purchase the capacity and energy of the New Hampshire Electric Cooperative, Inc.'s (NHEC) share of Seabrook 1 and to pay all of NHEC's Seabrook 1 costs for a ten-year period, which began on July 1, 1990. The total cost of purchases under this agreement was $23.4 million in 1997, $14.6 million in 1996 and $15.8 million in 1995. The total cost of these purchases has been collected through the FPPAC in accordance with the Rate Agreement. In connection with the agreement, NHEC agreed to continue as a firm-requirements customer of PSNH for 15 years. Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO and HWP have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO and HWP are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual O&M and capital costs of these facilities. Estimated Annual Costs: The estimated annual costs of the NU system's significant long-term contractual arrangements are as follows: - ----------------------------------------------------------------------------- (Millions of Dollars) 1998 1999 2000 2001 2002 - ----------------------------------------------------------------------------- VYNPC $ 28.7 $ 28.9 $ 27.7 $ 30.3 $ 31.5 NUGs 455.5 471.1 477.5 488.5 498.9 NHEC 30.0 30.0 14.6 -- -- Hydro-Quebec 32.6 31.6 30.9 30.0 29.3 ============================================================================= For additional information regarding the recovery of purchased power costs, see Note 2K, "Summary of Significant Accounting Policies -- Recoverable Energy Costs." G. Sale of COE During 1997, the NU Board of Trustees approved the offering for sale of COE. COE's revenues and earnings historically have not been material to NU. During the fourth quarter of 1997, management established a reserve of $25 million to reflect the anticipated loss from the sale of a COE investment. NU had a net investment in COE of approximately $33.4 million and $57.2 million, as of December 31, 1997 and 1996, respectively. 9. Market Risk Management Fuel Price Management: CL&P uses swap, collar, put and call instruments with financial institutions to hedge against some of the fuel price risk created by long-term negotiated energy contracts and nuclear replacement power generation and fuel purchases. These agreements minimize exposure associated with rising fuel prices by managing a portion of CL&P's cost of fuel for these negotiated energy contracts and nuclear replacement power generation and fuel purchases. As of December 31, 1997, CL&P had outstanding agreements with a total notional value of approximately $327 million, and a negative mark-to-market position of approximately $21 million. The terms of the agreements require CL&P to post cash collateral with its counterparties in the event of negative mark-to-market positions and lowered credit ratings. The amount of the collateral is to be returned to CL&P when the mark-to-market position becomes positive, when CL&P meets specified credit ratings or when an agreement ends and all open positions are properly settled. At December 31, 1997, cash collateral in the amount of $15.4 million was posted under these terms. Interest Rate Management: NAEC uses swap instruments with financial institutions to hedge against interest rate risk associated with its $200 million variable- rate bank note. The interest-rate management instruments employed eliminate the exposure associated with rising interest rates, and effectively fix the interest rate for this borrowing arrangement. Under the agreements, NAEC exchanges quarterly payments based on a differential between a fixed contractual interest rate and the three-month LIBOR rate at a given time. As of December 31, 1997, NAEC had outstanding agreements with a total notional value of $200 million and a positive mark-to-market position of approximately $104 thousand. Credit Risk: These agreements have been made with various financial institutions, each of which is rated "A3" or better by Moody's rating group. Each respective company will be exposed to credit risk on their respective market risk-management instruments if the counterparties fail to perform their obligations. However, management anticipates that the counterparties will be able to fully satisfy their obligations under the agreements. 10. Minority Interest in Consolidated Subsidiary CL&P Capital LP (CL&P LP, a subsidiary of CL&P) had previously issued $100 million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS), Series A. CL&P has the sole ownership interest in CL&P LP, as a general partner, and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance, CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million capital contribution, back to CL&P in the form of an unsecured debenture. CL&P consolidates CL&P LP for financial reporting purposes. Upon consolidation, the unsecured debenture is eliminated, and the MIPS securities are accounted for as minority interests. 11. Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and nuclear decommissioning trusts: The carrying amounts approximate fair value. SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," requires investments in debt and equity securities to be presented at fair value. As a result of this requirement, the investments held in the NU system companies' nuclear decommissioning trusts were adjusted to market by approximately $69.6 million as of December 31, 1997, and $31.4 million as of December 31, 1996, with corresponding offsets to the accumulated provision for depreciation. The amounts adjusted in 1997 and in 1996 represent cumulative gross unrealized holding gains. The cumulative gross unrealized holding losses were immaterial for both 1997 and 1996. Preferred stock and long-term debt: The fair value of the system's fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of the system's financial instruments and the estimated fair values are as follows: - --------------------------------------------------------------------------- At December 31, 1997 - --------------------------------------------------------------------------- Carrying Fair (Thousands of Dollars) Amount Value - --------------------------------------------------------------------------- Preferred stock not subject to mandatory redemption $ 136,200 $ 79,141 Preferred stock subject to mandatory redemption 276,000 255,180 Long-term debt -- First Mortgage Bonds 2,228,800 2,210,423 Other long-term debt 1,668,533 1,691,362 MIPS 100,000 100,760 =========================================================================== - --------------------------------------------------------------------------- At December 31, 1996 - --------------------------------------------------------------------------- Carrying Fair Thousands of Dollars) Amount Value - --------------------------------------------------------------------------- Preferred stock not subject to mandatory redemption $ 136,200 $ 127,045 Preferred stock subject to mandatory redemption 301,000 264,304 Long-term debt -- First Mortgage Bonds 2,196,788 2,163,031 Other long-term debt 1,718,859 1,741,818 MIPS 100,000 108,520 ========================================================================== The fair values shown above have been reported to meet disclosure requirements and do not purport to represent the amounts at which those obligations would be settled. Management's Discussion and Analysis Financial Condition Overview The length of the ongoing outages at the three Millstone nuclear plants (Millstone) and the high costs of the recovery efforts weakened NU's 1997 earnings, balance sheet and cash flows and will continue to have an adverse impact on NU's financial condition until the units are returned to service. NU's earnings fell sharply in 1997 for the second consecutive year, primarily as a result of costs associated with the ongoing Millstone outages. NU lost $1.01 per common share in 1997, compared with a profit of $0.30 per common share in 1996 and $2.24 a share in 1995. The poorer financial results in 1997 were due primarily to the fact that all three Millstone units were off line for the entire year in 1997 and spending associated with the recovery efforts was significantly higher in 1997 than it was in 1996. Millstone 3 operated for nearly three months in 1996 and Millstone 2 for nearly two months. As a result, the cost of replacing power ordinarily generated by the Millstone units rose by approximately $80 million in 1997. The total operation and maintenance (O&M) costs at Millstone were approximately $216 million higher in 1997. The higher Millstone costs have caused the NU system, primarily The Connecticut Light and Power Company (CL&P) and Western Massachusetts Electric Company (WMECO), to focus closely on maintaining adequate liquidity and reducing nonnuclear O&M costs. In 1997 and early 1998, CL&P and WMECO successfully sold $260 million in first mortgage bonds and renegotiated more than $400 million of bank credit lines. Additionally, nonnuclear O&M expenses in 1997 were reduced by about $50 million from 1996. The SEC has advised NU, CL&P, PSNH and WMECO to adjust for certain costs associated with the ongoing Millstone outages as they are incurred. For the past two years, NU, CL&P, PSNH and WMECO have been reserving for the unavoidable costs they expected to incur to meet NRC requirements. These annual statements have been adjusted in accordance with the SEC's directive. Management does not expect implementation of this accounting change to affect the ability of CL&P and WMECO to meet their financial covenants contained in their $313.75 million revolving credit arrangement. In 1998, management expects Millstone-related expenses to fall significantly, assuming Millstone 3 and Millstone 2 are returned to service at dates close to current estimates, although the O&M expenses at Millstone 3 and Millstone 2 will be considerably higher than before the station was placed on the Nuclear Regulatory Commission's (NRC's) watch list. The actual level of 1998 nuclear spending at Millstone will depend on when the units return to operation and the cost of restoring them to service. The company hopes to restart Millstone 3, the newest and largest unit at the site, in the early spring of 1998 and Millstone 2 three to four months after Millstone 3. The company cannot restart the Millstone units until it receives formal approval from the NRC. As part of an effort to reduce spending in 1998, Millstone 1 has been placed in extended maintenance status. Management will review its options with respect to Millstone 1 in 1998, including restart, early retirement and other options. Rate reductions in all three states served by NU's operating companies are likely to offset a portion of the benefit of lower Millstone-related costs. On December 1, 1997, Public Service Company of New Hampshire (PSNH) rates were reduced 6.87 percent as a result of an interim rate order issued by the New Hampshire Public Utilities Commission (NHPUC). On March 1, 1998, CL&P rates were reduced by approximately 1.4 percent to reflect the removal of Millstone 1 from rates, and additional noncash reductions were made to revenue requirements as a result of an interim rate order issued by the Connecticut Department of Public Utility Control (DPUC). Also on March 1, 1998, WMECO reduced retail rates by 10 percent in compliance with industry restructuring legislation passed in November 1997 by the Massachusetts Legislature. Rate cases involving CL&P and PSNH may result in additional rate adjustments later in 1998. CL&P's revenues could be further reduced if substantial delays in restarting Millstone 3 and Millstone 2 result in a DPUC decision to remove those units from rates. In addition to focusing on maintaining liquidity, management also must attend to industry restructuring efforts throughout the NU system's service territory. A temporary restraining order issued by a U.S. District Court is currently blocking the NHPUC from implementing a February 1997 restructuring order that would have resulted in a write-off by PSNH of more than $400 million. Management hopes to negotiate an alternative restructuring proposal in 1998 that will produce significant PSNH rate reductions and allow retail customers to choose their electric suppliers, but still give PSNH and North Atlantic Energy Corporation (NAEC) an opportunity to maintain an adequate financial condition and earn fair returns on their investments. The 1997 Massachusetts legislation allowed full retail choice on March 1, 1998. WMECO expects to recover fully its stranded costs through a combination of securitization and divestiture of its nonnuclear generating assets. In Connecticut, restructuring legislation is being considered in the legislative session that began in February 1998. Restructuring also is likely to cause other NU subsidiaries to auction their nuclear and/or nonnuclear generating units. Despite these potential requirements, management believes that it could be advantageous for the NU system to remain in the generation business, which could be accomplished by acquiring ownership interests in facilities inside and outside New England. NU's earnings in 1997 also were affected by a $25 million reserve for anticipated losses on the sale of investments by Charter Oak Energy, Inc., NU's independent power development subsidiary. Presently, NU is New England's largest electric utility system with 1.7 million customers in Connecticut, New Hampshire and Massachusetts. In 1997, NU experienced modest economic growth in its retail sales that was offset by the effects of mild winter weather. In 1998, management expects that the regional economy will continue to experience modest growth. Millstone Outages The NU system has a 100 percent ownership interest in Millstone 1 and 2 and a 68 percent ownership interest in Millstone 3. Millstone 1, 2 and 3 have been out of service since November 4, 1995, February 21, 1996, and March 30, 1996, respectively. Subsequent to its January 31, 1996, announcement that Millstone had been placed on its watch list, the NRC stated that the units cannot return to service until independent, third-party verification teams have reviewed the actions taken to improve the design, configuration and employee concerns issues that prompted the NRC to place the units on its watch list. The actual date of the return to service for each of the units is dependent upon the completion of independent inspections, reviews by the NRC and a vote by the NRC commissioners. In January 1998, NU declared Millstone 3 physically ready for restart, which meant that almost all of the restart-required physical work had been completed in the plant. The NRC currently is conducting a series of inspections to determine, among other things, whether the plant has effective leadership and corrective action and employee concerns programs. The Independent Corrective Action Verification Program, an NRC-ordered independent review of the plant's design and licensing bases, is expected to be completed in March 1998. In 1997, the NU system's share of nonfuel O&M costs expensed for Millstone increased to approximately $556 million, compared to approximately $340 million in 1996. Replacement power costs attributable to the Millstone outages totaled approximately $340 million in 1997 compared to $260 million expensed in 1996. These costs for 1998 are forecasted to average approximately $9 million per month for Millstone 3, $9 million per month for Millstone 2 and $6 million per month for Millstone 1 while the plants are out of service. CL&P, WMECO and PSNH have been, and will continue to be, expensing all of the costs to restart the units including replacement power and nonfuel O&M expenses. See "Connecticut Rate Matters" for issues related to the recovery of Millstone 1 costs. NU and its subsidiaries are involved in several class action lawsuits and other litigation in connection with their nuclear operations. See the "Notes to Consolidated Financial Statements," Note 8B, for further information on this litigation. Millstone 1 Management will review its options with respect to Millstone 1 during 1998. The issues that management will consider in evaluating its options include the costs to restart the unit, the economic benefits of the unit's continued operation and certain Connecticut state law issues. In the CL&P four year rate review proceeding (discussed in detail under "Rate Matters"), the DPUC noted that CL&P may not be able to recover its remaining investment in Millstone 1 if the DPUC were to determine that the unit had been prematurely shut down due to management imprudence. Additionally, there is a Connecticut statute which may limit CL&P's ability to collect decommissioning charges in the future if Millstone 1 were to be prematurely retired. CL&P's net unrecovered Millstone 1 plant cost and the unrecovered decommissioning costs at December 31, 1997, were approximately $216 million and $198 million, respectively. Capacity During 1996 and continuing into 1997, the NU system companies took measures to improve their capacity position, including obtaining additional generating capacity, improving the availability of NU's generating units and improving the NU system's transmission capability. During 1997, NU spent approximately $58 million to ensure the availability of adequate generating capacity in Connecticut and Massachusetts, of which $40 million was expensed. In 1998, NU does not anticipate the need to take additional measures to ensure adequate generating capacity. Liquidity and Capital Resources Cash provided from operations decreased approximately $438 million in 1997, compared to 1996, primarily due to higher cash expenditures related to the Millstone outages, and the pay down in 1997 of the 1996 year end accounts payable balance. The 1996 year end accounts payable balance was relatively high due to costs related to a severe December storm and costs associated with the Millstone outages that had been incurred but not yet paid by the end of 1996. Net cash used for financing activities decreased approximately $224 million, primarily due to suspension of the NU common dividend early in 1997 and an increase in short-term borrowings. CL&P and WMECO established facilities in 1996 under which they may sell, from time to time, up to $200 million and $40 million, respectively, of their accounts receivable and accrued utility revenues. As of December 31, 1997, CL&P and WMECO sold approximately $70 million and $20 million of receivables, respectively, to third-party purchasers. NU's, CL&P's and WMECO's three-year revolving credit agreement was amended in May 1997 (the Credit Agreement). Under the Credit Agreement, CL&P and WMECO are able to borrow up to approximately $225 million and $90 million, respectively, subject to a total borrowing limit of $313.75 million for all three borrowers. NU will be able to borrow up to $50 million when NU, CL&P and WMECO have each maintained a consolidated operating income to consolidated interest expense ratio of at least 2.50 to 1 for two consecutive fiscal quarters. Currently, the companies cannot meet this requirement. At December 31, 1997, CL&P and WMECO had $35 million and $15 million outstanding, respectively, under the Credit Agreement. In February 1998, because of borrowing restrictions on NU in the Credit Agreement, NU entered into a separate $25 million, 364-day revolving credit facility with one bank. Each major subsidiary of NU finances its own needs. Neither CL&P nor WMECO has any financing agreements containing cross defaults based on financial defaults by NU, PSNH or NAEC. Similarly, neither PSNH nor NAEC has any financing agreements containing cross defaults based on financial defaults by NU, CL&P or WMECO. Nevertheless, it is possible that investors will take negative operating results or regulatory developments at one company in the NU system into account when evaluating other companies in the NU system. That could, as a practical matter and despite the contractual and legal separations among the NU companies, negatively affect each company's access to financial markets. In December 1997 and January 1998, Moody's Investors Service (Moody's) and Standard & Poor's (S&P), respectively, downgraded the senior secured debt of CL&P, WMECO and NU, as well as the preferred stock of CL&P and WMECO. This was the fourth time Moody's and S&P have downgraded CL&P and WMECO securities since the Millstone units went on the NRC watch list in 1996. All of the NU system's securities are rated below investment grade and remain under review for further downgrade. Although CL&P and WMECO do not have any plans to issue debt in the near term, rating agency downgrades generally increase the future cost of borrowing funds because lenders will want to be compensated for increased risk. Additionally, this could affect the terms and ability of the NU system companies to extend existing agreements. The downgrade by Moody's of WMECO's first mortgage bonds to Ba2 in December 1997 brought those ratings to a level at which the sponsor of WMECO's accounts receivable program can take various actions, in its discretion, which would have the practical effect of limiting WMECO's ability to utilize the facility. The WMECO accounts receivable program could be terminated if WMECO's first mortgage bond credit ratings experience one more level of downgrade. CL&P's accounts receivables program could be terminated if its senior secured debt is downgraded two more steps from its current ratings. The NU system companies' ability to borrow under their financing arrangements is dependent on their satisfaction of contractual borrowing conditions. The financial covenants that must be satisfied to permit CL&P and WMECO to borrow under the Credit Agreement are particularly restrictive and become more restrictive throughout 1998. Spending levels in 1998, particularly for the first half of the year while the Millstone units are expected to be out of service, will be constrained to levels intended to assure that the financial covenants in CL&P's and WMECO's Credit Agreement are satisfied. However, there is no assurance that these financial covenants will be met as the system may encounter additional unexpected costs from such areas as storms, reduced revenues from regulatory actions or the effect of weather on sales levels. If the return to service of Millstone 3 or Millstone 2 is delayed substantially beyond the present restart estimates, if some borrowing facilities become unavailable because of difficulties in meeting borrowing conditions or renegotiating extensions, if the system encounters additional significant costs, or any other significant deviations from management's current assumptions, the currently available borrowing facilities could be insufficient to meet all of the NU system's cash requirements. In those circumstances, management would take even more stringent actions to reduce costs and cash outflows and would attempt to take other actions to obtain additional sources of funds. The availability of these funds would be dependent upon the general market conditions and the NU system's credit and financial condition at that time. Restructuring The NU system companies continue to operate under cost-of-service based regulation, however, future rates and the recovery of strandable costs are issues under various restructuring initiatives in each of the NU system companies' service territories. Strandable costs are expenditures or commitments that have been made to meet public service obligations with the expectation that they would be recovered from customers in the future. The NU system companies have exposure to strandable costs for their investments in high-cost nuclear generating plants, state-mandated purchased power obligations and significant regulatory assets. The NU system companies' exposure to strandable investments and purchased power obligations exceeds their shareholder's equity. The NU system's financial strength and resulting ability to compete in a restructured environment will be negatively affected if the NU system companies are unable to recover their past investments and commitments. Even if the NU system companies are given the opportunity to recover a large portion of their strandable costs, earnings prospects in a restructured environment will be affected in ways which cannot be estimated at this time. The NU system companies are seeking to mitigate the impacts of restructuring by proposing stable, lower rates while pursuing customer choice options and full recovery of their strandable costs. The NU system companies' strategy to recover strandable costs includes efforts to promote state legislation that will authorize the issuance of rate reduction bonds that would refinance these investments and which would be repaid through non-bypassable charges to customers. Management is unable to predict the ultimate outcome of these initiatives which will be subject to regulatory and legislative approvals. Management believes it is entitled to full recovery of its prudently incurred costs, including regulatory assets and other strandable costs. See the "Notes to Consolidated Financial Statements," Note 8A, for the potential accounting impacts of restructuring. New Hampshire In February 1997, the NHPUC issued orders to restructure the state's electric utility industry and set interim stranded cost charges for PSNH. In the orders, the NHPUC announced a departure from cost-based ratemaking and adopted a market-priced approach to stranded cost recovery. PSNH, NU, NAEC, and Northeast Utilities Service Company (NUSCO) filed for a temporary restraining order, preliminary and permanent injunctive relief and a declaratory judgment in the United States District Court of New Hampshire. The case subsequently was transferred to the United States District Court of Rhode Island (District Court) where a temporary restraining order was granted, staying, indefinitely, the enforcement of the NHPUC's restructuring orders as they affected PSNH. Certain appeals to the preliminary ruling have been denied and proceedings in the District Court are expected to resume. The NHPUC conducted rehearing proceedings in 1997 to decide the appropriate methodology to be used to determine PSNH's interim stranded costs and to set PSNH's interim stranded cost charges utilizing the determined methodology. The NHPUC has not indicated when it will issue a decision in these proceedings. On December 15, 1997, the NHPUC officially announced that industry restructuring would not take place on January 1, 1998. As part of the rehearing proceedings, PSNH proposed a new methodology to quantify its stranded costs. Under this proposal, PSNH would divest its owned generation and purchased power obligations via auction. To the extent that the auction fails to produce sufficient revenues to cover the net book value of owned generation and contractual payment obligations of purchased power, the difference would be recovered from customers through a non-bypassable distribution charge. The new proposal also relies upon securitization of certain assets to further reduce rates. On February 20, 1998, PSNH forwarded a settlement offer to representatives from the state of New Hampshire that was consistent with PSNH's proposal in the rehearing proceedings including, among other things, a 20 percent rate reduction at the beginning of 1999, an auction of PSNH's nonnuclear generating units and Securitization of approximately $1.15 billion of PSNH's stranded costs. Massachusetts On November 25, 1997, Massachusetts enacted a comprehensive electric utility industry restructuring bill. The bill provides that each Massachusetts electric company, including WMECO, will decrease its rates by 10 percent and allow all its customers to choose their electric supplier on March 1, 1998. The statute requires a further 5 percent rate reduction, adjusted for inflation, by September 1, 1999. In addition, the legislation provides, among other things, for: (i) recovery of strandable costs through a "transition charge" to customers, subject to review by the Department of Telecommunications and Energy (DTE), formerly the Department of Public Utilities (DPU, collectively the DTE), (ii) a possible limitation on WMECO's return on equity should its transition cost charge go above a certain level, (iii) securitization of allowed strandable costs, and (iv) divestiture of nonnuclear generation. WMECO hopes it will be able to complete securitization in 1998. The statute also provides that an electric company must transfer or separate ownership of generation, transmission and distribution facilities into independent affiliates or functionally separate such facilities within 30 business days after federal approval. Additionally, marketing companies formed by an electric company are to be separate from the electric company and separate from generation, transmission or distribution affiliates. On December 31, 1997, WMECO filed its restructuring plan with the DTE consistent with the Massachusetts restructuring legislation. The plan sets out the process by which WMECO, as of March 1, 1998, initiated a 10 percent rate reduction for all customer rate classes and allowed customers to choose their energy supplier. WMECO intends to mitigate its strandable costs through several steps, including divesting WMECO's nonnuclear generating plants at an auction to be held as soon as June 30, 1998, and securitization of approximately $500 million of stranded costs. NU intends to participate through a nonregulated affiliate in the competitive bid process for WMECO's generation resources. Any proceeds in excess of book value received from the divestiture of these units will be used to mitigate stranded costs. As required by the legislation, WMECO will continue to operate and maintain the transmission and local distribution network and deliver electricity to all customers. On February 20, 1998, the DTE issued an order approving, in all material respects, WMECO's restructuring plan on an interim basis. A final decision is expected in 1998. Because WMECO is obligated to reduce rates on March 1, 1998, before the means of financing for restructuring are completed, WMECO's cash flows and financial condition will be negatively affected. These impacts would become significant if there are material delays in, or significantly reduced proceeds from, the divestiture of nonnuclear generation and securitization. Connecticut Massachusetts and New Hampshire have been at the forefront of the restructuring movement in New England with very different approaches as previously discussed. In Connecticut, legislators have proposed broad restructuring legislation which will be considered in the spring of 1998. Rate Matters Connecticut In July 1996, the DPUC approved a rate settlement agreement with CL&P (the Settlement). Under the Settlement, CL&P froze base rates until at least December 31, 1997, and agreed to accelerate the amortization of regulatory assets during the period that the rate freeze remains in effect. The Settlement provided that CL&P's target return on equity (ROE) would be 10.7 percent but did not alter CL&P's allowed ROE of 11.7 percent. If CL&P's actual ROE for a calendar year exceeds 10.7 percent after the target regulatory asset amortization ($68 million in 1997) and after adjustment for any incremental NRC billings and any rate disallowances for nuclear operations, then CL&P shall retain two-thirds of any surplus and use the remaining one-third to provide a reduction in bills. CL&P's actual ROE, as adjusted, fell below the target ROE for 1996 and 1997 and, therefore, the accelerated amortization of regulatory assets was reduced to the minimum amounts allowed under the Settlement ($73 million in 1996 and $54 million in 1997). For each full year that the rate freeze remains in effect, CL&P agreed to amortize an additional $44 million of regulatory assets. On July 30, 1997, the DPUC issued a decision in its prudence review of nuclear cost recovery issues disallowing CL&P's recovery of all of the replacement power costs associated with the ongoing outages at Millstone. CL&P has expensed, and will continue to expense, replacement power costs for the Millstone outages as they are incurred. The DPUC is required to review a utility's rates every four years if there has not been a rate proceeding during such period. In 1997, the DPUC conducted such a review of CL&P's rates, including an analysis of the possibility of removing one or more of the Millstone nuclear units from CL&P's rate base. On December 31, 1997, the DPUC issued its ruling in this matter. The decision did not effect a change in CL&P's rates, but set forth findings and conclusions that could be used to do so in additional proceedings. The most significant conclusion was that Millstone 1 should be removed from CL&P's rate base, which would cause an annual revenue reduction of approximately $30.5 million. The decision stated that the DPUC would open an interim rate case immediately to remove Millstone 1 from CL&P's rates and simultaneously to remove an additional $110.5 million of other expenses from rates related to perceived overearnings. In February 1998, the DPUC issued a decision reducing CL&P's rates by approximately 1.4 percent to reflect the removal of Millstone 1 from rates. This reduction reflects the removal from rates of O&M, depreciation and investment return related to Millstone 1, net of replacement power costs. In addition, the decision requires CL&P to accelerate the amortization of regulatory assets by $110.5 million, which includes the $44 million from the 1996 Settlement. The interim rate reduction became effective on March 1, 1998. CL&P also was directed to file a full rate case on June 1, 1998, to address potential overearnings amounting to an additional $150 million in 1998. The effective date of any rate order will be September 28, 1998. In addition, the DPUC has scheduled a hearing for April 1, 1998, to determine the status of Millstone 3 and Millstone 2. A similar restart status hearing is anticipated for June 1, 1998. If the units are not operating by those dates, the DPUC will consider their removal from rates. The DPUC also will consider CL&P's analyses of the economic benefits of the continued operation of Millstone 1 and Millstone 2 in the context of CL&P's next integrated resource planning proceeding, which begins in April 1998. New Hampshire PSNH's Rate Agreement provides for seven base rate increases and a comprehensive fuel and purchased power adjustment clause (FPPAC). In June 1996, the final base rate increase of 5.5 percent went into effect. Although the FPPAC continues for an additional four years beyond the end of the fixed rate period, there is uncertainty regarding how it will function after that time. On May 2, 1997, PSNH made a rate filing with the NHPUC requesting base rates to remain at their current level after May 31, 1997. By order dated November 6, 1997, the NHPUC ordered a temporary rate reduction for PSNH at a revenue level 6.87 percent lower than current rates. The NHPUC also set an interim return on equity of 11 percent. The temporary rates became effective December 1, 1997. A final decision, which will be reconciled to July 1, 1997, is not expected to be issued until September 1998. A portion of this reduction was offset by an increase to rates through the FPPAC. On February 10, 1998, the NHPUC ordered an FPPAC rate for the period December 1, 1997, through May 31, 1998, which increased customer bills by approximately 6 percent. This rate continues to defer recovery of a substantial portion of costs for the future. In addition, recovery of the Seabrook deferred return (approximately $127 million annually) is scheduled to begin in June 1998. See the "Notes to Consolidated Financial Statements," Note 2K, for further information on the FPPAC. Massachusetts In April 1996, the DTE approved a settlement (the Agreement) that included the continuation through February 1998 of a 2.4 percent rate reduction instituted in June 1994. Additionally, the Agreement terminated certain pending and potential reviews of WMECO's generating plant performance and accelerated its amortization of strandable generation assets by approximately $6 million in 1996 and $10 million in 1997. On August 20, 1997, WMECO filed with the DTE a joint motion for approval of a settlement agreement with the Massachusetts Attorney General for a fuel adjustment clause (FAC) which would allow for a lower rate to WMECO customers for the billing months of September 1997 through February 1998. WMECO is not recovering replacement power costs during this period and has indicated that it would not seek recovery of any replacement power costs associated with the Millstone outages. WMECO has been expensing and will continue to expense these costs. The Massachusetts restructuring legislation effectively eliminates the FAC, effective March 1, 1998. Nuclear Decommissioning Connecticut Yankee The NU system has a 49 percent ownership interest in the Connecticut Yankee nuclear generating facility (CY or the plant). On December 4, 1996, the Board of Directors of Connecticut Yankee Atomic Power Company voted unanimously to cease permanently the production of power at the plant. The decision to retire CY from commercial operation was based on an economic analysis of the costs of operating it compared to the costs of closing it and incurring replacement power costs over the remaining period of the plant's operating license, which would have expired in 2007. The economic analysis showed that closing the plant and incurring replacement power costs produced substantial savings. CY has undertaken a number of regulatory filings intended to implement the decommissioning. In late December 1996, CY filed an amendment to its power contracts with the FERC to clarify the obligations of its purchasing utilities following the decision to cease power production. At December 31, 1997, NU's share of these obligations was approximately $304 million, including the cost of decommissioning and the recovery of existing assets. Management expects that CL&P, PSNH and WMECO each will continue to be allowed to recover such FERC approved costs from their customers. Accordingly, NU has recognized its share of the estimated costs as a regulatory asset, with a corresponding obligation, on its balance sheet. Maine Yankee The NU system has a 20 percent ownership interest in the Maine Yankee (MY) nuclear generating facility. On August 6, 1997, the Board of Directors of Maine Yankee Atomic Power Company (MYAPC) voted unanimously to retire MY. On January 14, 1998, FERC released a draft order on the MYAPC application to amend its power contracts with the owner/purchasers and revise its decommissioning and other charges. FERC has accepted the proposed application for filing and made the amendments and the proposed charges under the contracts effective on January 15, 1998, subject to refund after hearings. At December 31, 1997, the NU system's share of the estimated remaining obligation, including decommissioning, amounted to approximately $173 million. Under the terms of the contracts with MYAPC, the shareholders' sponsor companies, including CL&P, PSNH and WMECO, are responsible for their proportionate share of the costs of the unit, including decommissioning. Management expects that CL&P, PSNH and WMECO will be allowed to recover these costs from their customers. Accordingly, NU has recognized these costs as a regulatory asset, with a corresponding obligation on its balance sheet. Millstone and Seabrook NU's estimated cost to decommission its shares of the Millstone plants and Seabrook is approximately $1.48 billion in year end 1997 dollars. These costs are being recognized over the lives of the respective units with a portion currently being recovered through rates. As of December 31, 1997, the market value of the contributions already made to the decommissioning trusts, including their investment returns, was approximately $503 million. See the "Notes to Consolidated Financial Statements," Note 3, for further information on nuclear decommissioning, including the NU system's share of costs to decommission the other regional nuclear generating units. Environmental Matters NU's subsidiaries are potentially liable for environmental cleanup costs at a number of sites inside and outside their service territories. To date, the future estimated environmental remediation liability has not been material with respect to the earnings or financial position of the NU system. At December 31, 1997, NU's subsidiaries had recorded an environmental reserve of approximately $16 million. See the "Notes to Consolidated Financial Statements," Note 8C, for further information on environmental matters. Year 2000 Issue The Year 2000 issue exists because many computer systems and applications currently use two-digit date fields to designate a year. As the change of the century occurs, date-sensitive systems may recognize the year 2000 as 1900, or not recognize it at all. This inability to recognize or properly treat the year 2000 may cause NU's systems to process critical financial and operational information incorrectly. The company has assessed and continues to assess the impact of the Year 2000 issue on its operating and reporting systems. The assessment of the nuclear operating systems is continuing and is expected to be completed in the summer of 1998. The NU system will utilize both internal and external resources to reprogram or replace and test the software for Year 2000 modifications. The total estimated remaining cost of the Year 2000 project is $37 million and is being funded through operating cash flows. This estimate does not include any costs for the replacement or repair of equipment or devices that may be identified during the assessment process. The majority of these costs will be expensed as incurred over the next two years. To date, the company has incurred and expensed approximately $4 million related to the assessment of, and preliminary efforts in connection with, its Year 2000 project. The costs of the project and the date on which the company plans to complete the Year 2000 modifications are based on management's best estimates, which were derived utilizing numerous assumptions of future events, including the continued availability of certain resources, third-party modification plans and other factors. However, there can be no guarantee that these estimates will be achieved, and actual results could differ materially from those plans. If the NU system's remediation plan is not successful, there could be a significant disruption of the NU system's operations. Risk-Management Instruments The following discussion about the NU system's risk-management activities includes forward looking statements that involve risk and uncertainties. Actual results could differ materially from those projected in the forward looking statements. This analysis presents the hypothetical loss in earnings related to the fuel price and interest rate market risks not covered by the risk-management instruments at December 31, 1997. The NU system uses swaps, collars, puts and calls to manage the market risk exposures associated with changes in fuel prices and variable interest rates. The NU system does not use these risk-management instruments for speculative purposes. For more information on NU's use of risk- management instruments, see the "Notes to Consolidated Financial Statements," Notes 2.0 and 9. Fuel Price Risk-Management Instruments In the generation of electricity, the most significant variable cost component is the cost of fuel. Typically, most of CL&P's fuel purchases are protected by a regulatory fuel price adjustment clause. However, for a specific, well-defined volume of fuel that is excluded from the fuel price adjustment clause (unprotected volume), CL&P employs fuel price risk-management instruments to protect itself against the risk of rising fuel prices, thereby limiting fuel costs and protecting its profit margins. These risks are created by the sale of long-term, fixed-price electricity contracts to wholesale customers and the purchase or generation of replacement power related to the ongoing Millstone nuclear outages. At December 31, 1997, CL&P had outstanding agreements with a total notional value of approximately $327 million. The settlement amounts associated with the instruments reduced fuel expense by approximately $8 million. CL&P has had experience using various fuel price risk-management instruments since 1994, most of which have been in the form of fuel price swaps. At December 31, 1997, approximately 30 percent of the unprotected volume was covered by fuel price risk-management instruments (hedge ratio) for 1997. This effectively fixed or bounded the fuel cost and thus eliminated the market price risk for this covered volume of fuel. At December 31, 1997, CL&P had a hedge ratio of 44 percent for 1998. At December 31, 1997, the 56 percent uncovered volume of fuel for 1998, as a result of not being hedged, is subject to changes in actual market prices. Therefore, assuming a hypothetical 10 percent increase in the average 1997 price of fuel in 1998, the result would be a negative pretax impact on earnings of approximately $12.4 million. This analysis is based on the broad assumption that the entire uncovered volume of fuel remains constant and will be purchased on the spot market. This assumption is subject to change as the uncovered volume of fuel likely will change during the next year. Other assumptions used in this analysis, projections of the fuel mix, the amount of long-term sales contracts or the projected Millstone restart dates, also are subject to change. Interest Rate Risk-Management Instruments Several NU subsidiaries hold variable rate long-term notes, exposing the NU system to interest rate risk. In order to hedge some of this risk, interest rate risk-management instruments have been entered into on NAEC's $200 million variable rate note, effectively fixing the interest on this note at 7.823 percent. The remaining variable notes remain unhedged. At December 31, 1997, NU had a hedge ratio on its long-term variable rate notes of 21 percent, which is expected to be the same for 1998. The remaining 79 percent of NU's variable notes are unhedged and, as a result, are subject to actual market rates for 1998. Thus, a 10 percent increase in market interest rates above the 1997 weighted average variable rate during 1998 would result in a $3.6 million pretax annual decrease in earnings. For purposes of this analysis, the hedge ratio for long-term variable rate notes is calculated by dividing the amount of the hedged long-term note by the total of all long-term variable notes held at December 31, 1997. Results of Operations The components of significant income statement variances for the past two years are provided in the table below. The relative magnitude of how revenues earned in 1997 and retained earnings were used by NU's continuing operations in 1997 is illustrated in the chart on page 21. Income Statement Variances (Millions of Dollars) 1997 over/(under) 1996 1996 over/(under) 1995 Amount Percent Amount Percent Operating revenues $ 43 1% $ 42 1% Fuel, purchased and net interchange power 154 13 230 25 Other operation 3 - 127 13 Maintenance 86 21 127 44 Amortization of regulatory assets, net 8 7 (6) (5) Federal and state income taxes (94) (98) (166) (63) Deferred nuclear plants return (other and borrowed funds) (3) (13) (13) (36) Other income, net (69) (a) 20 (a) Interest on long-term debt (3) (1) (30) (10) Other interest (4) (53) 1 15 Preferred dividends of subsidiaries (3) (10) (6) (14) Net income (169) (a) (244) (86) (a) Percentage greater than 100 Operating Revenues Total operating revenues increased in 1997, primarily due to higher fuel recoveries and higher conservation recoveries. Fuel recoveries increased $32 million, primarily due to higher fuel revenues for CL&P as a result of a lower fuel rate in 1996. Conservation recoveries increased by $17 million, primarily due to a 1996 reserve for overrecoveries of CL&P demand-side management costs. Retail kilowatt hour sales were 0.3 percent lower in 1997 as a result of mild winter weather. Total operating revenues increased in 1996, primarily due to higher retail sales, regulatory decisions and higher other revenues, partially offset by lower fuel recoveries and lower wholesale revenues. Retail sales increased 1.6 percent ($40 million), primarily due to modest economic growth in 1996. Regulatory decisions increased revenues by $22 million, primarily due to retail rate increases for CL&P in mid-1995 and PSNH in mid-1995 and 1996, partially offset by 1996 reserves for CL&P overrecoveries of demand-side management costs. Other revenues increased $31 million and included higher recognition in 1996 of reimbursable conservation services and higher transmission revenues. Fuel recoveries decreased $40 million, primarily due to lower FPPAC revenues for PSNH as a result of a customer refund ordered by the NHPUC, partially offset by higher base fuel revenues for PSNH as a result of the PSNH rate increases. Wholesale revenues decreased $13 million, primarily due to higher recognition in 1995 of lump-sum payments for the termination of a CL&P long-term contract and capacity sales contracts that expired in 1995. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased in 1997, primarily due to replacement power costs associated with the Millstone outages and the expensing in 1997 of replacement power costs incurred in 1996. Fuel, purchased and net interchange power expense increased in 1996, primarily due to replacement power costs associated with the Millstone outages and the write-off of the generation utilization adjustment clause (GUAC) balance under the CL&P Settlement. Other Operation and Maintenance Other operation and maintenance expenses increased in 1997, primarily due to higher costs associated with the Millstone restart effort ($216 million), higher costs as a result of Seabrook outages ($23 million) and higher capacity charges from Maine Yankee ($16 million), partially offset by lower recognition of nuclear refueling outage costs primarily as a result of the 1996 CL&P Rate Settlement ($72 million), lower capacity charges from Connecticut Yankee as a result of a property tax refund ($35 million), lower administrative and general expenses ($41 million) primarily due to lower pensions and benefit costs, and lower storm expenses. Other operation and maintenance expenses increased in 1996, primarily due to higher costs associated with the Millstone restart effort ($116 million) and 1996 costs to ensure adequate generating capacity in Connecticut ($39 million). In addition, 1996 costs reflect higher storm and reliability expenditures, higher recognition of conservation expenses and higher marketing costs. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net increased in 1997, primarily due to the completion of the CL&P cogeneration deferrals in 1996, increased amortization in 1997, and the beginning of the amortization of NAEC's Seabrook deferred return in December 1997, partially offset by the completion of CL&P's Seabrook amortization and WMECO's Millstone 3 amortization in 1996. Amortization of regulatory assets, net decreased in 1996, primarily due to the completion of the Millstone 3 phase-in plans in 1995, partially offset by lower CL&P cogeneration deferrals and the accelerated amortization of regulatory assets as a result of the 1996 CL&P Settlement. Federal and State Income Taxes Federal and state income taxes decreased in 1997, primarily due to lower book taxable income. Federal and state income taxes decreased in 1996, primarily due to lower book taxable income, partially offset by 1995 tax benefits from a favorable tax ruling and the expiration of the 1991 federal statute of limitations. Income tax expense totaled approximately $95 million in 1996, despite relatively low pretax earnings, due to the tax effect of differences for certain items, particularly depreciation and the amortization of PSNH acquisition costs. Deferred Nuclear Plants Return The change in deferred nuclear plants return in 1997 was not significant. Deferred nuclear plants return decreased in 1996, primarily due to additional Seabrook investment being phased into rates, partially offset by a one-time adjustment to NAEC's Seabrook deferred return balance of approximately $5 million in 1995. Other Income, Net Other income, net decreased in 1997, primarily due to a $25 million reserve for anticipated losses on the sale of investments by Charter Oak Energy (COE), equity losses on COE investments, costs associated with the accounts receivable facility, nonutility marketing and advertising costs and lower miscellaneous income. Other income, net increased in 1996, primarily due to higher interest income on temporary cash investments in 1996, the 1995 write-down of CL&P's wholesale investment in Millstone 3 and a 1995 increase to the environmental reserve. Interest on Long-Term Debt The change in interest on long-term debt in 1997 was not significant. Interest on long-term debt decreased in 1996, primarily due to reacquisitions and retirements of long-term debt in 1995. Other Interest Other interest expense decreased in 1997 due to 1996 interest expense associated with an FPPAC refund for PSNH. Preferred Dividends of Subsidiaries The change in preferred dividends of subsidiaries was not significant in 1997. Preferred dividends of subsidiaries decreased in 1996, primarily due to a 1995 charge to earnings for premiums on redeemed preferred stock and a reduction in preferred stock levels. 1997 Use of Revenue and Retained Earnings [The following table was originally a pie chart in the printed materials.] Energy Costs 32% Nonfuel Operation and Maintenance Expenses 28% Depreciation, Amortization and Other Expenses 13% Wages and Benefits 12% Interest Charges 7% Taxes 6% Common and Preferred Dividends 2% NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Quarterly Financial Data (Restated) (Unaudited)
- --------------------------------------------------------------------------------------------------------- 1997 Quarter Ended (a) - --------------------------------------------------------------------------------------------------------- (Thousands of Dollars, except per share data) March 31 June 30 September 30 December 31 - --------------------------------------------------------------------------------------------------------- Operating Revenues.....................................$ 975,368 $ 903,323 $ 977,127 $ 978,988 - --------------------------------------------------------------------------------------------------------- Operating Income.......................................$ 69,377 $ 23,542 $ 46,361 $ 51,502 - --------------------------------------------------------------------------------------------------------- Net Income/(Loss)......................................$ 876 $ (47,017) $ (30,832) $ (52,989) - --------------------------------------------------------------------------------------------------------- Earnings/(Loss) Per Common Share.......................$ 0.01 $ (0.37) $ (0.24) $ (0.41) - --------------------------------------------------------------------------------------------------------- - --------------------------------------------------------------------------------------------------------- 1996 - --------------------------------------------------------------------------------------------------------- Operating Revenues.....................................$1,028,202 $ 871,904 $ 955,518 $ 936,524 - --------------------------------------------------------------------------------------------------------- Operating Income.......................................$ 155,433 $ 87,725 $ 63,432 $ 2,080 - --------------------------------------------------------------------------------------------------------- Net Income/(Loss)......................................$ 87,674 $ 17,572 $ (3,567) $ (62,750) - --------------------------------------------------------------------------------------------------------- Earnings/(Loss) Per Common Share.......................$ 0.68 $ 0.14 $ (0.03) $ (0.49) - ---------------------------------------------------------------------------------------------------------
Consolidated Generation Statistics
- --------------------------------------------------------------------------------------------------------- 1997 1996 1995 1994 1993 - --------------------------------------------------------------------------------------------------------- Source of Electric Energy:(kWh-millions) Nuclear--Steam (b)......................... 3,778 9,405 18,235 19,443 22,965 Fossil--Steam.............................. 13,155 9,188 9,162 8,292 7,676 Hydro--Conventional........................ 1,260 1,544 1,099 1,239 1,140 Hydro--Pumped Storage...................... 959 1,217 1,209 1,195 1,269 Internal Combustion........................ 184 206 37 13 8 Energy Used for pumping.................... (1,327) (1,668) (1,674) (1,629) (1,749) - --------------------------------------------------------------------------------------------------------- Net Generation............................. 18,009 19,892 28,068 28,553 31,309 - --------------------------------------------------------------------------------------------------------- Purchased and Net Interchange.............. 24,377 22,111 14,256 14,028 10,499 Company Use and Unaccounted for............ (2,802) (2,473) (2,706) (2,535) (2,591) - --------------------------------------------------------------------------------------------------------- Net Energy Sold............................ 39,584 39,530 39,618 40,046 39,217 ========================================================================================================= System Capability--MW (b)(c)............... 8,312.0 8,894.0 8,394.8 8,494.8 7,795.3 System PeaK Demand--MW..................... 6,455.5 5,946.9 6,358.2 69,338.5 6,191.0 Nuclear Capacity--MW (b)(c)................ 2,785.0 3,117.8 3,239.6 3,272.6 3,110.0 Nuclear Contribution to Total Energy Requirements(%) (b)................ 13.0 28.0 52.0 54.0 62.1 Nuclear Capacity Factor(%) (d)............. 19.6 38.0 69.9 67.5 80.8 ========================================================================================================= (a) Reclassifications of prior data have been made to conform with the current presentation. (b) Includes the NU system's entitlements in regional nuclear generating companies, net of capacity sales and purchases. (c) Millstone 1, 2 and 3 have been out of service since November 4, 1995, Febuary 21, 1996 and March 30, 1996, respectively. The company has restructured its nuclear organization and is currently implementing comprehensive plans to restart the units. The actual date of the return to service for each of the units is dependent upon the completion of independent inspections and reviews by the NRC and a vote by the NRC commissioners. NU hopes to return Millstone 3 to service in early spring of 1998 and Millstone 2 three to fours months after Millstone 3. Millstone 1 is currently in extended maintenance status. (d) Represents the average capacity factor for the nuclear units operated by the NU system.
NORTHEAST UTILITIES AND SUBSIDIARIES Selected Consolidated Financial Data
- ------------------------------------------------------------------------------------------------------ (Thousands of Dollars, except 1997 1996 percentages and per share data) (Restated) (Restated) 1995 1994 1993 - ------------------------------------------------------------------------------------------------------ Balance Sheet Data: Net Utility Plant (a)................$ 6,463,158 $ 6,732,165 $ 7,000,837 $ 7,282,421 $ 7,439,159 Total Assets......................... 10,414,412 10,741,748 10,559,574 10,584,880 10,668,164 Total Capitalization (b)............. 6,472,504 6,659,617 6,820,624 7,035,989 7,309,898 Obligations Under Capital Leases (b). 207,731 206,165 230,482 239,121 243,760 - ------------------------------------------------------------------------------------------------------ Income Data: Operating Revenues...................$ 3,834,806 $ 3,792,148 $ 3,750,560 $ 3,642,742 $ 3,629,093 Net(Loss)/Income..................... (129,962) 38,929 282,434 286,874 249,953 (c) - ------------------------------------------------------------------------------------------------------ Common Shate Data: (Loss)/Earnings per Share............ ($1.01) $0.30 $2.24 $2.30 $2.02 (c) Dividends per Share (d).............. $0.25 $1.38 $1.76 $1.76 $1.76 Number of Shares Outstanding--Average................ 129,567,708 127,960,382 126,083,645 124,678,192 123,947,631 Market Price--High................... $14 1/4 $25 1/4 $25 3/8 $25 3/4 $28 7/8 Market Price--Low.................... $7 5/8 $9 1/2 $21 $20 3/8 $22 Market Price--Closing (end of year).. $11 13/16 $13 1/8 $24 1/4 $21 5/8 $23 3/4 Book Value per Share (end of year)... $16.67 $18.02 $19.08 $18.47 $17.89 Rate of Return Earned on Average Common Equity (%)................... (5.8) 1.6 12.0 12.7 11.4 Market-to-Book Ratio (end of year)... 0.7 0.7 1.3 1.2 1.3 - ------------------------------------------------------------------------------------------------------ Capitalization: Common Shareholders' Equity.......... 34% 35% 36% 33% 30% Preferred Stock (b)(e)............... 6 6 7 9 9 Long-Term Debt (b)................... 60 59 57 58 61 - ------------------------------------------------------------------------------------------------------ Total Capitalization................. 100% 100% 100% 100% 100% ====================================================================================================== (a) Includes the reclassification of the unamortized PSNH acquisition costs to net utility plant. (b) Includes portions due within one year. (c) Includes the cumulative effect of change in accounting for municipal property tax expense, which increased earnings for common shares and earnings per share by $51.7 million and $0.42, respectively. (d) Quarterly dividends were suspended effective March 25, 1997. (e) Excludes $100 million of Monthly Income Preferred Securities.
NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Sales Statistics
- --------------------------------------------------------------------------------------------------------- 1997 1996 1995 1994 (a) 1993 - --------------------------------------------------------------------------------------------------------- Revenues: (thousands) Residential.......................... $ 1,499,394 $ 1,501,465 $ 1,469,988 $ 1,430,239 $ 1,385,818 Commercial........................... 1,266,449 1,246,822 1,230,608 1,173,808 (b) 1,043,125 Industrial........................... 560,782 565,900 583,204 559,801 (b) 649,876 Other Utilities...................... 329,764 315,577 303,004 330,801 383,129 Streetlighting and Railroads......... 48,867 48,053 47,510 45,943 45,480 Non-Franchised Sales................. 21,476 8,360 - - - Miscellaneous........................ 47,446 23,513 50,353 44,140 60,008 - --------------------------------------------------------------------------------------------------------- Total Electric.................... 3,774,178 3,709,690 3,684,667 3,584,732 3,567,436 Other................................ 60,628 82,458 65,893 58,010 61,657 - --------------------------------------------------------------------------------------------------------- Total............................. $ 3,834,806 $ 3,792,148 $ 3,750,560 $ 3,642,742 $ 3,629,093 ========================================================================================================= Sales: (kWh - millions) Residential.......................... 12,099 12,241 12,005 12,231 11,988 Commercial........................... 12,091 12,012 11,737 11,649 (b) 10,304 Industrial........................... 6,801 6,820 6,842 6,729 (b) 7,572 Other Utilities...................... 8,034 8,032 8,718 9,123 9,046 Streetlighting and Railroads......... 318 319 316 314 307 Non-Franchised Sales................. 241 50 - - - - --------------------------------------------------------------------------------------------------------- Total............................. 39,584 39,474 39,618 40,046 39,217 ========================================================================================================= Customers: (average) Residential.......................... 1,535,134 1,532,015 1,526,127 1,513,987 1,503,182 Commercial........................... 159,350 157,347 156,652 154,703 (b) 155,487 Industrial........................... 7,804 7,792 7,861 7,813 (b) 6,272 Other................................ 3,929 3,916 3,878 3,818 3,793 - --------------------------------------------------------------------------------------------------------- Total............................. 1,706,217 1,701,070 1,694,518 1,680,321 1,668,734 ========================================================================================================= Average Annual Use per Residential Customer (kWh).... 7,898 8,005 7,880 (c) 8,152 7,987 ========================================================================================================= Average Annual Bill per Residential Customer.......... $ 978.72 $ 980.19 $ 964.88 (c)$ 953.23 $ 923.32 ========================================================================================================= Average Revenue (in cents) per kWh: Residential.......................... 12.39 12.27 12.24 11.69 11.56 Commercial........................... 10.47 10.38 10.49 10.08 10.12 Industrial........................... 8.25 8.30 8.52 8.32 8.58 ========================================================================================================= (a) Effective January 1, 1994, the accounting for unbilled revenues was revised to report unbilled revenues by customer class. (b) Effective January 1, 1994, approximately 1,300 customers previously classified as commercial customers were reclassified to industrial customers. (c) Effective January 1, 1996, the amounts shown reflect billed and unbilled sales. 1995 has been restated to reflect this change.
EX-13.2 3 ANNUAL REPORT OF CLP EXHIBIT 13.2 THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES AMENDED 1997 ANNUAL REPORT The Connecticut Light and Power Company and Subsidiaries Amended 1997 Annual Report Index Contents Page Consolidated Balance Sheets (Restated)............................... 2-3 Consolidated Statements of Income (Restated)......................... 4 Consolidated Statements of Cash Flows (Restated)..................... 5 Consolidated Statements of Common Stockholder's Equity (Restated).................................................... 6 Notes to Consolidated Financial Statements (Restated)................ 7 Report of Independent Public Accountants............................. 41 Management's Discussion and Analysis of Financial Condition and Results of Operations (Restated)..................... 42 Selected Financial Data (Restated)................................... 54 Statements of Quarterly Financial Data (Restated).................... 54 Statistics........................................................... 55 Preferred Stockholder and Bondholder Information..................... Back Cover PART I. FINANCIAL INFORMATION THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
- ----------------------------------------------------------------------------------------- At December 31, 1997 1996 (Restated) (Restated) - ----------------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS - ------ Utility Plant, at original cost: Electric................................................. $ 6,411,018 $ 6,283,736 Less: Accumulated provision for depreciation.......... 2,902,673 2,665,519 ------------- ------------- 3,508,345 3,618,217 Construction work in progress............................ 93,692 95,873 Nuclear fuel, net........................................ 135,076 133,050 ------------- ------------- Total net utility plant.............................. 3,737,113 3,847,140 ------------- ------------- Other Property and Investments: Nuclear decommissioning trusts, at market................ 369,162 296,960 Investments in regional nuclear generating companies, at equity.................................... 58,061 56,925 Other, at cost........................................... 66,625 16,565 ------------- ------------- 493,848 370,450 ------------- ------------- Current Assets: Cash..................................................... 459 404 Notes receivable from affiliated companies............... - 109,050 Investments in securitizable assets...................... 205,625 - Receivables, less accumulated provision for uncollectible accounts of $300,000 in 1997 and of $13,240,000 in 1996............................. 50,671 226,112 Accounts receivable from affiliated companies............ 3,150 3,481 Taxes receivable......................................... 70,311 40,134 Accrued utility revenues................................. - 78,451 Fuel, materials and supplies, at average cost............ 81,878 79,937 Recoverable energy costs, net--current portion........... 28,073 25,436 Prepayments and other.................................... 79,632 63,344 ------------- ------------- 519,799 626,349 ------------- ------------- Deferred Charges: Regulatory assets........................................ 1,292,818 1,370,781 Unamortized debt expense................................. 19,286 17,033 Other.................................................... 18,359 12,283 ------------- ------------- 1,330,463 1,400,097 ------------- ------------- Total Assets......................................... $ 6,081,223 $ 6,244,036 ============= =============
The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------------- At December 31, 1997 1996 (Restated) (Restated) - ---------------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock--$10 par value. Authorized 24,500,000 shares; outstanding 12,222,930 shares in 1997 and 1996................................ $ 122,229 $ 122,229 Capital surplus, paid in................................ 641,333 639,657 Retained earnings (Note 1).............................. 419,972 580,779 ------------- ------------- Total common stockholder's equity.............. 1,183,534 1,342,665 Cumulative preferred stock-- $50 par value - authorized 9,000,000 shares; outstanding 5,424,000 shares in 1997 and 1996; $25 par value - authorized 8,000,000 shares; outstanding no shares in 1997 and 1996 Not subject to mandatory redemption.................... 116,200 116,200 Subject to mandatory redemption........................ 151,250 155,000 Long-term debt.......................................... 2,023,316 1,834,405 ------------- ------------- Total capitalization........................... 3,474,300 3,448,270 ------------- ------------- Minority Interest in Consolidated Subsidiary.............. 100,000 100,000 ------------- ------------- Obligations Under Capital Leases.......................... 18,042 143,347 ------------- ------------- Current Liabilities: Notes payable to banks.................................. 35,000 - Notes payable to affiliated company..................... 61,300 - Long-term debt and preferred stock--current portion................................................ 23,761 204,116 Obligations under capital leases--current portion................................................ 140,076 12,361 Accounts payable........................................ 124,427 160,945 Accounts payable to affiliated companies................ 92,963 78,481 Accrued taxes........................................... 33,017 28,707 Accrued interest........................................ 14,650 31,513 Other................................................... 23,495 34,433 ------------- ------------- 548,689 550,556 ------------- ------------- Deferred Credits: Accumulated deferred income taxes....................... 1,348,617 1,386,772 Accumulated deferred investment tax credits............. 127,713 135,080 Deferred contractual obligations........................ 348,406 305,627 Other................................................... 115,456 174,384 ------------- ------------- 1,940,192 2,001,863 ------------- ------------- Commitments and Contingencies (Note 12) Total Capitalization and Liabilities........... $ 6,081,223 $ 6,244,036 ============= =============
The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
- ----------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) - ----------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues................................... $2,465,587 $2,397,460 $2,387,069 ----------- ----------- ----------- Operating Expenses: Operation -- Fuel, purchased and net interchange power....... 977,543 831,079 608,600 Other........................................... 726,420 727,674 614,382 Maintenance........................................ 355,772 300,005 192,607 Depreciation....................................... 238,667 247,109 242,496 Amortization of regulatory assets, net............. 61,648 57,432 54,217 Federal and state income taxes..................... (59,436) 957 178,346 Taxes other than income taxes...................... 172,592 174,062 172,395 ----------- ----------- ----------- Total operating expenses (Note 1)............ 2,473,206 2,338,318 2,063,043 ----------- ----------- ----------- Operating (Loss)/Income.............................. (7,619) 59,142 324,026 ----------- ----------- ----------- Other Income: Equity in earnings of regional nuclear generating companies............................. 5,672 6,619 6,545 Other, net......................................... (1,856) 20,710 14,585 Minority interest in income of subsidiary.......... (9,300) (9,300) (8,732) Income taxes....................................... 7,573 160 (2,978) ----------- ----------- ----------- Other income, net............................ 2,089 18,189 9,420 ----------- ----------- ----------- (Loss)/Income before interest charges........ (5,530) 77,331 333,446 ----------- ----------- ----------- Interest Charges: Interest on long-term debt......................... 132,127 127,198 124,350 Other interest..................................... 1,940 1,001 3,880 ----------- ----------- ----------- Interest charges, net........................ 134,067 128,199 128,230 ----------- ----------- ----------- Net (Loss)/Income (Note 1)........................... $ (139,597) $ (50,868) $ 205,216 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
- ----------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) - ----------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Activities: Net(Loss)/Income............................................ $(139,597) $ (50,868) $ 205,216 Adjustments to reconcile to net cash from operating activities: Depreciation.............................................. 238,667 247,109 242,496 Deferred income taxes and investment tax credits, net..... (10,400) (39,642) 49,520 Deferred nuclear plants return, net of amortization....... (281) 7,746 95,559 Amortization of deferred demand-side-management costs, net 38,029 26,941 (937) Recoverable energy costs, net of amortization............. (9,533) (35,567) (16,169) Amortization of deferred cogeneration costs, net.......... 32,700 25,957 (55,341) Deferred nuclear refueling outage, net of amortization ... (45,333) 45,643 (20,712) Other sources of cash..................................... 64,013 75,552 86,956 Other uses of cash........................................ (50,137) (23,862) (53,745) Changes in working capital: Receivables and accrued utility revenues.................. 184,223 (22,378) (33,032) Fuel, materials and supplies.............................. (1,941) (11,455) (4,479) Accounts payable.......................................... (22,036) 83,951 9,605 Accrued taxes............................................. 4,310 (23,561) 25,855 Sale of receivables and accrued utility revenues.......... 70,000 - - Investment in securitizable assets........................ (205,625) - - Other working capital (excludes cash)..................... (74,266) (5,385) (1,869) ---------- ---------- ---------- Net cash flows from operating activities (Note 1)............. 72,793 300,181 528,923 ---------- ---------- ---------- Financing Activities: Issuance of long-term debt.................................. 200,000 222,000 - Issuance of Monthly Income Preferred Securities....................................... - - 100,000 Net increase/(decrease) in short-term debt.................. 96,300 (51,750) (127,000) Reacquisitions and retirements of long-term debt............ (204,116) (14,329) (10,866) Reacquisitions and retirements of preferred stock........... - - (125,000) Cash dividends on preferred stock........................... (15,221) (15,221) (21,185) Cash dividends on common stock.............................. (5,989) (138,608) (164,154) ---------- ---------- ---------- Net cash flows from/(used for) financing activities........... 70,974 2,092 (348,205) ---------- ---------- ---------- Investment Activities: Investment in plant: Electric utility plant.................................... (155,550) (140,086) (131,858) Nuclear fuel.............................................. (702) 553 (1,543) ---------- ---------- ---------- Net cash flows used for investments in plant................ (156,252) (139,533) (133,401) Investment in NU system money pool.......................... 109,050 (109,050) - Investment in nuclear decommissioning trusts................ (45,314) (50,998) (47,826) Other investment activities, net............................ (51,196) (2,625) 581 ---------- ---------- ---------- Net cash flows used for investments........................... (143,712) (302,206) (180,646) ---------- ---------- ---------- Net Increase In Cash For The Period........................... 55 67 72 Cash - beginning of period.................................... 404 337 265 ---------- ---------- ---------- Cash - end of period.......................................... $ 459 $ 404 $ 337 ========== ========== ========== Supplemental Cash Flow Information: Cash paid/(refunded) during the year for: Interest, net of amounts capitalized........................ $ 145,962 $ 114,458 $ 117,074 ========== ========== ========== Income taxes................................................ $ (22,338) $ 77,790 $ 137,706 ========== ========== ========== Increase in obligations: Niantic Bay Fuel Trust and other capital leases............. $ 2,815 $ 2,855 $ 33,537 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- --------------------------------------------------------------------------------------- Capital Retained Common Surplus, Earnings(a) Total Stock Paid In (Note 1) - --------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1995............... $122,229 $632,117 $ 765,724 $1,520,070 Net income for 1995.................. 205,216 205,216 Cash dividends on preferred stock.............................. (21,185) (21,185) Cash dividends on common stock....... (164,154) (164,154) Loss on the retirement of preferred stock............... (125) (125) Capital stock expenses, net.......... 5,864 5,864 --------- --------- ---------- ----------- Balance at December 31, 1995............. 122,229 637,981 785,476 1,545,686 Net loss for 1996 (Note 1)........... (50,868) (50,868) Cash dividends on preferred stock.............................. (15,221) (15,221) Cash dividends on common stock....... (138,608) (138,608) Capital stock expenses, net.......... 1,676 1,676 --------- --------- ---------- ----------- Balance at December 31, 1996 (Restated).. 122,229 639,657 580,779 1,342,665 Net loss for 1997 (Note 1)........... (139,597) (139,597) Cash dividends on preferred stock.............................. (15,221) (15,221) Cash dividends on common stock....... (5,989) (5,989) Capital stock expenses, net.......... 1,676 1,676 --------- --------- ---------- ----------- Balance at December 31, 1997 (Restated).. $122,229 $641,333 $ 419,972 $1,183,534 ========= ========= ========== ===========
(a) The company has dividend restrictions imposed by its long-term debt agreements. At December 31, 1997, these restrictions totaled approximately $540 million. The accompanying notes are an integral part of these financial statements. The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SECURITIES AND EXCHANGE COMMISSION INQUIRY In a letter dated March 25, 1998, the Securities and Exchange Commission (SEC) inquired into Northeast Utilities' (NU) accounting for nuclear compliance costs. These costs are the unavoidable incremental costs associated with the current nuclear outages required to be incurred prior to restart of the units in accordance with correspondence received from the Nuclear Regulatory Commission (NRC) early in 1996. The SEC's view is that these unavoidable costs associated with nuclear outages and procedures to be implemented at nuclear power plants in response to regulatory requirements required prior to restart of the units should be expensed as incurred. During 1996 and 1997, NU and its wholly owned subsidiaries, The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO), reserved for these unavoidable incremental costs that they expected to incur to meet NRC standards. The SEC advised NU, CL&P, PSNH and WMECO to reflect these costs as they are incurred. While NU and its independent auditors, Arthur Andersen LLP, believed the accounting was required by, and was in accordance with, generally accepted accounting principles, the company has agreed to adjust its accounting for nuclear compliance costs and amend its 1996 and 1997 Form 10-K filings. The financial statements in this report have been restated to reflect the change in accounting. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. ABOUT THE CONNECTICUT LIGHT AND POWER COMPANY The Connecticut Light and Power Company and subsidiaries (the company or CL&P), WMECO, Holyoke Water Power Company (HWP), PSNH and North Atlantic Energy Corporation (NAEC) are the operating subsidiaries comprising the Northeast Utilities system (the NU system) and are wholly owned by NU. The NU system furnishes franchised retail electric service in Connecticut, New Hampshire and western Massachusetts through CL&P, PSNH, WMECO and HWP. A fifth wholly owned subsidiary, NAEC, sells all of its entitlement to the capacity and output of the Seabrook nuclear power plant (Seabrook) to PSNH. In addition to its franchised retail service, the NU system furnishes firm and other wholesale electric services to various municipalities and other utilities, and participates in limited retail access programs, providing off-system retail electric service. The NU system serves about 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues. Other wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing and other services to the NU system companies. Northeast Nuclear Energy Company (NNECO) acts as agent for the NU system companies and other New England utilities in operating the Millstone nuclear generating facilities. North Atlantic Energy Service Corporation (NAESCO) acts as agent for CL&P and NAEC and has operational responsibilities for Seabrook. In addition, CL&P and WMECO each have established a special purpose subsidiary whose business consists of the purchase and resale of receivables. B. PRESENTATION The consolidated financial statements of CL&P include the accounts of all wholly owned subsidiaries. Significant intercompany transactions have been eliminated in consolidation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity and are subject to approval by various federal and state regulatory agencies. For more information on significant subsidiaries of CL&P, see Note 11, "Sale of Customer Receivables and Accrued Utility Revenues," and Note 14, "Minority Interest in Consolidated Subsidiary." C. PUBLIC UTILITY REGULATION NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act). NU and its subsidiaries, including CL&P, are subject to the provisions of the 1935 Act. Arrangements among the NU system companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. CL&P is subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions. For information regarding proposed changes in the nature of industry regulation, see Note 2H, "Summary of Significant Accounting Policies - Regulatory Accounting and Assets," and Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). D. NEW ACCOUNTING STANDARDS The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS), SFAS 129, "Disclosure of Information about Capital Structure," in February 1997. SFAS 129 establishes standards for disclosing information about an entity's capital structure. CL&P's current disclosures are consistent with the requirements of SFAS 129. During June 1997, the FASB issued SFAS 130, "Reporting Comprehensive Income" and SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." SFAS 130 establishes standards for the reporting and disclosure of comprehensive income. To date, CL&P has not had material transactions that would be required to be reported as comprehensive income. SFAS 131 determines the standards for reporting and disclosing qualitative and quantitative information about a company's operating segments. This information includes segment profit or loss, certain segment revenue and expense items and segment assets and a reconciliation of these segment disclosures to corresponding amounts in the company's general purpose financial statements. CL&P currently evaluates management performance using a cost-based budget and the information required by SFAS 131 is not available. Therefore, these disclosure requirements are not applicable. Management believes that the implementation of SFAS 130 and SFAS 131 will not have a material impact on CL&P's current disclosures. See Note 11, "Sale of Customer Receivables and Accrued Utility Revenues," and Note 12C, "Commitments and Contingencies - Environmental Matters," for information on other newly adopted accounting and reporting standards related to those specific areas. E. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT Regional Nuclear Generating Companies: CL&P owns common stock of four regional nuclear generating companies (Yankee companies). The Yankee companies, with CL&P's ownership interests are: Connecticut Yankee Atomic Power Company(CYAPC) ............... 34.5% Yankee Atomic Electric Company (YAEC) ........................ 24.5 Maine Yankee Atomic Power Company (MYAPC) .................... 12.0 Vermont Yankee Nuclear Power Corporation (VYNPC) ............. 9.5 CL&P's investments in the Yankee companies are accounted for on the equity basis due to the company's ability to exercise significant influence over their operating and financial policies. CL&P's investments in the Yankee companies at December 31, 1997 are: (Thousands of Dollars) CYAPC .................................................. $38,358 YAEC ................................................... 5,128 MYAPC .................................................. 9,449 VYNPC .................................................. 5,126 $58,061 Each Yankee company owns a single nuclear generating unit. Under the terms of the contracts with the Yankee companies, the shareholders- sponsors are responsible for their proportionate share of the costs of each unit, including decommissioning. The energy and capacity costs from VYNPC and nuclear decommissioning costs of the Yankee companies that have been shut down are billed as purchased power to CL&P. The electricity produced by the Vermont Yankee nuclear generating facility (VY) is committed substantially on the basis of ownership interests and is billed pursuant to contractual agreements. YAEC's, CYAPC's and MYAPC's nuclear power plants were shut down permanently on February 26, 1992, December 4, 1996, and August 6, 1997, respectively. Under ownership agreements with the Yankee companies, CL&P may be asked to provide direct or indirect financial support for one or more of the companies. For more information on the Yankee companies, see Note 4, "Nuclear Decommissioning," and Note 12F, "Commitments and Contingencies - Long-Term Contractual Arrangements." Millstone 1: CL&P has an 81.0 percent joint ownership interest in Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approximately $387.7 million and $384.5 million, respectively, and the accumulated provision for depreciation included approximately $172.0 million and $159.4 million, respectively, for CL&P's share of Millstone 1. CL&P's share of Millstone 1 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. Millstone 2: CL&P has an 81.0 percent joint ownership interest in Millstone 2, an 870-MW nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approximately $694.7 million and $690.4 million, respectively, and the accumulated provision for depreciation included approximately $249.1 million and $224.1 million, respectively, for CL&P's share of Millstone 2. CL&P's share of Millstone 2 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. Millstone 3: CL&P has a 52.93 percent joint ownership interest in Millstone 3, a 1,154-MW nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approximately $1.9 billion each year and the accumulated provision for depreciation included approximately $552.7 million and $504.1 million, respectively, for CL&P's share of Millstone 3. CL&P's share of Millstone 3 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. The three Millstone units are out of service. NU hopes to return Millstone 3 to service in the early spring of 1998 and Millstone 2 three to four months after Millstone 3. Millstone 1 has been placed in extended maintenance status. Management is reviewing its options with respect to Millstone 1, including restart, early retirement and other options. In a draft ruling issued in February 1998, the Connecticut Department of Public Utility Control (DPUC) determined that Millstone 1 was no longer "used and useful" and ordered it removed from rate base. In 1996, one of the joint owners of Millstone 3, Vermont Electric Generation and Transmission Cooperative, Inc. (VEG&T), filed for bankruptcy. The subsequent liquidation resulted in the offering of VEG&T's 0.035 percent share of Millstone 3 for sale to the joint owners of Millstone 3. None of the non-NU joint owners accepted the offer. During 1998, CL&P expects to make the necessary regulatory filings to acquire ownership of VEG&T's share of Millstone 3. For more information regarding the DPUC's action, see the MD&A. For more information regarding the Millstone units see Note 4, "Nuclear Decommissioning," and Note 12B, "Commitments and Contingencies - Nuclear Performance." Seabrook 1: CL&P has a 4.06 percent joint ownership interest in Seabrook 1, a 1,148-MW nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approximately $174.3 million and $173.7 million, respectively, and the accumulated provision for depreciation included approximately $33.9 million and $29.7 million, respectively, for CL&P's share of Seabrook 1. CL&P's share of Seabrook 1 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. F. DEPRECIATION The provision for depreciation is calculated using the straight-line method based on estimated remaining lives of depreciable utility plant- in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency. Except for major facilities, depreciation rates are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.8 percent in 1997 and 4.0 percent in 1996 and 1995. See Note 4, "Nuclear Decommissioning," for information on nuclear decommissioning. CL&P's nonnuclear generating facilities have limited service lives. Plant may be retired in place or dismantled based upon expected future needs, the economics of the closure and environmental concerns. The costs of closure and removal are incremental costs and, for financial reporting purposes, are accrued over the life of the asset as part of depreciation. At December 31, 1997 and 1996, the accumulated provision for depreciation included approximately $45.8 million and $43.0 million, respectively, accrued for the cost of removal, net of salvage for nonnuclear generation property. G. REVENUES Other than revenues under fixed-rate agreements negotiated with certain wholesale, commercial and industrial customers and limited retail access programs, utility revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission. Regulatory commissions also have authority over the terms and conditions of nontraditional rate making arrangements. At the end of each accounting period, CL&P accrues an estimate for the amount of energy delivered but unbilled. For information on rate proceedings and their potential impact on CL&P, see the MD&A. H. REGULATORY ACCOUNTING AND ASSETS The accounting policies of CL&P and the accompanying consolidated financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered through future revenues. Through their actions, regulators also may reduce or eliminate the value of an asset, or create a liability. If any portion of CL&P's operations were no longer subject to the provisions of SFAS 71, as a result of a change in the cost-of- service based regulatory structure or the effects of competition, CL&P would be required to write off all of its related regulatory assets and liabilities unless there is a formal transition plan which provides for the recovery, through established rates, for the collection of approved stranded costs and to maintain the cost-of-service basis for the remaining regulated operations. At the time of transition, CL&P would be required to determine any impairment of the carrying costs of deregulated plant and inventory assets. Management anticipates that a restructuring program will be implemented within Connecticut during the next few years. In a restructured environment, CL&P's generation business no longer will be rate regulated on a cost-of-service basis. The majority of CL&P's regulatory assets are related to its generation business. The staff of the SEC has had concerns regarding the appropriateness of the utilities' ability to continue application of SFAS 71 for the generation portion of their business in a restructured environment. The SEC referred the issue to the Emerging Issues Task Force (EITF) of the FASB which reached a consensus and issued "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101," (EITF 97-4). The EITF concluded: (1) the future recognition of regulatory assets for the portion of the business that no longer qualifies for application of SFAS 71 depends on the regulators' treatment of the recovery of those costs and other stranded assets from cash flows of other portions of the business still considered to be regulated, and (2) a utility should discontinue the application of SFAS 71 when a legislative and regulatory plan has been enacted, which would include transition plans into a competitive environment, and when the stranded costs which are subject to future rate recovery are determined. EITF 97-4 became effective in August 1997. The Connecticut General Assembly is addressing a proposal for electric industry restructuring in the state of Connecticut during 1998. As the terms and conditions to be contained within the restructuring plan cannot be determined at this time, management believes that its use of regulatory accounting remains appropriate. CL&P expects that its transmission and distribution business will continue to be rate-regulated on a cost-of-service basis and, accordingly, CL&P will continue to apply SFAS 71 to this portion of its business. For further information on CL&P's regulatory environment and the potential impacts of restructuring, see Note 12A, "Commitments and Contingencies - Restructuring and Rate Matters" and the MD&A. SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires the evaluation of long- lived assets, including regulatory assets, for impairment when certain events occur or when conditions exist that indicate the carrying amounts of assets may not be recoverable. SFAS 121 requires that any long-lived assets which are no longer probable of recovery through future revenues be revalued based on estimated future cash flows. If this revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. Management continues to believe that it is probable that CL&P will recover its investments in long-lived assets through future revenues. This conclusion may change in the future as the implementation of restructuring plans in the state of Connecticut will generally require the formation of a separate generation entity that will be subject to competitive market conditions. As a result, CL&P will be required to assess the carrying amounts of its long-lived assets in accordance with SFAS 121. The components of CL&P's regulatory assets are as follows: At December 31, 1997 1996 (Thousands of Dollars) Income taxes, net (Note 2I) ................. $ 709,896 $ 753,390 Recoverable energy costs, net (Note 2J) ............................. 104,796 97,900 Deferred demand-side management costs (Note 2K) ........................... 52,100 90,129 Cogeneration costs (Note 2L) ................ 33,505 66,205 Unrecovered contractual obligations (Note 4) ...................... 338,406 300,627 Other ....................................... 54,115 62,530 $1,292,818 $1,370,781 I. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the ratemaking treatment of the applicable regulatory commissions. See Note 9, "Income Tax Expense" for the components of income tax expense. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, which give rise to the accumulated deferred tax obligation is as follows: At December 31, 1997 1996 (Restated) (Restated) (Thousands of Dollars) Accelerated depreciation and other plant-related differences ................ $1,056,690 $1,032,857 Regulatory assets - income tax gross up ................................. 304,276 313,420 Net operating loss carryforwards ........... (7,670) - Other ...................................... (4,679) 40,495 $1,348,617 $1,386,772 At December 31, 1997, CL&P had a state of Connecticut net operating loss carryforward of approximately $131 million which can be used against CL&P and its affiliates' combined Connecticut taxable income and which, if unused, expires in the year 2002. J. RECOVERABLE ENERGY COSTS Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (D&D assessment). The Energy Act requires that regulators treat D&D assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P is currently recovering these costs through rates. As of December 31, 1997, CL&P's total D&D deferrals were approximately $50.1 million. During 1997, CL&P implemented an energy adjustment clause (EAC) under which fuel prices above or below base-rate levels are charged or credited to customers. The EAC replaced CL&P's fuel adjustment and generation utilization adjustment clauses and is designed to reconcile and adjust the difference between actual fuel costs and the fuel revenue collected through base rates on a six-month basis. For the period January 1, 1997 through June 30, 1997, CL&P agreed to a zero EAC rate. For the period July 1, 1997 through December 31, 1997, the DPUC approved an EAC rate through which CL&P recovered approximately $11.5 million of deferred fuel costs. While this proceeding did not include provisions for the recovery of approximately $18 million of costs related to the early closing of CYAPC's nuclear generating unit, it did allow for the recovery of costs, subject to refund, related to the closure of MYAPC's nuclear generating unit. CL&P has appealed the DPUC's ruling related to CYAPC replacement power costs. During December 1997, the DPUC approved an EAC rate for the period January 1, 1998 through June 30, 1998. During this period, CL&P will recover approximately $27.9 million of deferred fuel costs. At December 31, 1997, CL&P's net recoverable energy costs, excluding current net recoverable energy costs, were approximately $104.8 million. For further information on recoverable energy costs, see the MD&A. K. DEMAND-SIDE MANAGEMENT (DSM) CL&P's DSM costs are recovered in base rates through a Conservation Adjustment Mechanism. CL&P is allowed to recover DSM costs in excess of costs reflected in base rates over periods ranging from approximately four to ten years. During April 1997, the DPUC approved CL&P's DSM budget of $36 million for 1997. In October 1997, CL&P and other interested parties filed a stipulation with the DPUC requesting that the DPUC approve certain programs and establish a budget level of $32.7 million for 1998 and $28.8 million for 1999. The $52.1 million of DSM costs on CL&P's books as of December 31, 1997, currently being collected, will be fully recovered by 2000. L. COGENERATION COSTS Beginning on July 1, 1996, the deferred cogeneration balance of approximately $86 million is being amortized over a five year period. An additional $9 million of amortization was applied to the deferred balance in 1997, as required under a settlement agreement which CL&P reached with the DPUC. CL&P continues to apply any savings associated facility to the deferred balance. Under current expectations, CL&P expects complete amortization of the deferred balance by December 31, 1998. At December 31, 1997, CL&P's deferred cogeneration costs balance was approximately $33.5 million. M. SPENT NUCLEAR FUEL DISPOSAL COSTS Under the Nuclear Waste Policy Act of 1982, CL&P must pay the United States Department of Energy (DOE) for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. Fees for nuclear fuel burned on or after April 7, 1983, are billed currently to customers and paid to the DOE on a quarterly basis. For nuclear fuel used to generate electricity prior to April 7, 1983 (prior-period fuel), payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the three-month Treasury Bill Yield Rate. At December 31, 1997, fees due to the DOE for the disposal of prior-period fuel were approximately $166.5 million, including interest costs of $99.9 million. The DOE was originally scheduled to begin accepting delivery of spent fuel in 1998. However, delays in identifying a permanent storage site have continually postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. The company has primary responsibility for the interim storage of its spent nuclear fuel. Current capability to store spent fuel at Millstone 1 and 2 are estimated to be adequate until 2004 and at Seabrook until 2010. Storage facilities for Millstone 3 are expected to be adequate for the projected life of the unit. Meeting spent fuel storage requirements beyond these periods could require new and separate storage facilities, the costs for which have not been determined. In November 1997, the U.S. District Court of Appeals for the D.C. Circuit ruled that the lack of an interim storage facility does not excuse the DOE from meeting its contractual obligation to begin accepting spent nuclear fuel no later than January 31, 1998. Currently, the DOE has not taken the spent nuclear fuel as scheduled and, as a result, may have to pay contract damages. The ultimate outcome of this legal proceeding is uncertain at this time. N. MARKET RISK-MANAGEMENT POLICIES CL&P utilizes market risk-management instruments, including swaps, collars, puts and calls, to hedge well-defined risks associated with changes in fuel prices. To qualify for hedge treatment, the underlying hedged item must expose CL&P to risks associated with market fluctuations and the market-risk management instrument used must be designated as a hedge and must reduce the company's exposure to market fluctuations throughout the period. Amounts receivable or payable under fuel-price management instruments are recognized in operating revenues when realized. CL&P does not use market risk-management instruments for speculative purposes. For further information, see Note 13, "Market Risk Management." 3. LEASES CL&P and WMECO may finance up to $400 million of nuclear fuel for Millstone 1 and 2 and their respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement which is scheduled to expire July 31, 1998. The NBFT capital lease agreement, which was amended in February 1998, requires CL&P and WMECO to secure their obligation to repay the NBFT with up to $90 million of first mortgage bonds. CL&P and WMECO will issue these bonds by May 1998. CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel consumed in the reactors based on a units-of-production method at rates which reflect estimated kilowatt hours of energy provided plus financing costs associated with the fuel in the reactors. Upon permanent discharge from the reactors, ownership of the nuclear fuel transfers to CL&P and WMECO. CL&P has also entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, gas turbines, nuclear control room simulators and office space. The provisions of these lease agreements generally provide for renewal options. The following rental payments have been charged to expense: Year Capital Leases Operating Leases 1997 ........... $10,457,000 $19,749,000 1996 ........... 17,993,000 22,032,000 1995 ........... 56,307,000 23,793,000 Interest included in capital lease rental payments was $9,948,000 in 1997, $10,144,000 in 1996 and $10,587,000 in 1995. Future minimum rental payments, excluding executory costs such as property taxes, state use taxes, insurance and maintenance, under long-term noncancelable leases as of December 31, 1997, are: Year Capital Leases Operating Leases (Thousands of Dollars) 1998............... $142,500 $ 22,700 1999............... 2,900 21,300 2000............... 2,900 19,900 2001............... 2,900 14,400 2002............... 3,000 6,200 After 2002......... 54,300 22,800 Future minimum lease payments.............. 208,500 $107,300 Less amount representing interest.............. 50,400 Present value of future minimum lease payments........ $158,100 Rocky River Realty Company (RRR) provides real estate support services, including the leasing of properties and facilities, used by NU system companies, including CL&P. During 1997, RRR repurchased certain notes that were secured by real estate leases between RRR as lessor and NUSCO as lessee. The repayment of these notes triggered the acceleration of rent and CL&P was subsequently billed by NUSCO and paid its proportionate share of the accelerated lease obligation. At December 31, 1997, CL&P has recorded long-term prepaid rent of approximately $11.1 million. This asset is being amortized on a straight line basis and will be fully amortized in 2017. 4. NUCLEAR DECOMMISSIONING Millstone and Seabrook: CL&P's nuclear power plants have service lives that are expected to end during the years 2010 through 2026. Upon retirement, these units must be decommissioned. Current decommissioning studies concluded that complete and immediate dismantlement at retirement continues to be the most viable and economic method of decommissioning the three Millstone units and Seabrook 1. Decommissioning studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology and inflation. The estimated cost of decommissioning CL&P's ownership share of Millstone 1 and 2, in year-end 1997 dollars, is $390.9 million and $350.2 million, respectively. CL&P's ownership share of the estimated cost of decommissioning Millstone 3 and Seabrook 1 in year-end 1997 dollars, is $294.0 million and $19.2 million, respectively. The Millstone units and Seabrook 1 decommissioning costs will be increased annually by their respective escalation rates. Nuclear decommissioning costs are accrued over the expected service life of the units and are included in depreciation expense on the Consolidated Statements of Income. Nuclear decommissioning costs amounted to $37.8 million each year in 1997 and 1996 and $30.5 million in 1995. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Consolidated Balance Sheets. At December 31, 1997 and 1996, the balance in the accumulated reserve for depreciation amounted to $407.3 million and $329.1 million, respectively. CL&P has established external decommissioning trusts through a trustee for its portion of the costs of decommissioning Millstone 1, 2 and 3. CL&P's portion of the cost of decommissioning Seabrook 1 is paid to an independent decommissioning financing fund managed by the state of New Hampshire. Funding of the estimated decommissioning costs assumes levelized collections for the Millstone units and escalated collections for Seabrook 1 and after-tax earnings on the Millstone and Seabrook decommissioning funds of approximately 5.5 percent and 6.5 percent, respectively. As of December 31, 1997, CL&P has collected through rates $277.9 million toward the future decommissioning costs of its share of the Millstone units, of which $240.3 million has been transferred to external decommissioning trusts. As of December 31, 1997, CL&P has paid approximately $2.9 million into Seabrook 1's decommissioning financing fund. Earnings on the decommissioning trusts and financing fund increase the decommissioning trust and the accumulated reserve for depreciation. Unrealized gains and losses associated with the decommissioning trusts and financing fund also impact the balance of the trusts and the accumulated reserve for depreciation. Changes in requirements or technology, the timing of funding or dismantling or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. CL&P attempts to recover sufficient amounts through its allowed rates to cover its expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by regulatory agencies is reflected in CL&P's rates. Based on present estimates and assuming its nuclear units operate to the end of their respective license periods, CL&P expects that the decommissioning trusts and financing fund will be substantially funded when the units are retired from service. Millstone 1 has been placed in extended maintenance status while management is reviewing its options with respect to the unit. These include restart, early retirement and other options. Relating to management's consideration of the option to immediately retire Millstone 1 are certain Connecticut state law issues. In its four-year rate review proceeding, the DPUC noted that CL&P may not be able to obtain its remaining investment in Millstone 1 if it were to determine that the unit had been prematurely shut down due to management imprudence. Additionally, there is a Connecticut statute which may limit CL&P's ability to collect future decommissioning charges related to Millstone 1 if Millstone 1 were to be terminated before the end of its expected life. At December 31, 1997, CL&P's net unrecovered Millstone 1 plant costs were $215.7 million and the remaining unrecovered decommissioning costs were approximately $198 million. Yankee Companies: VYNPC owns and operates a nuclear generating unit with a service life that is expected to end in 2012. CL&P's ownership share of estimated costs, in year-end 1997 dollars, of decommissioning this unit is $48.0 million. On August 6, 1997, the board of directors of MYAPC voted unanimously to cease permanently the production of power at its nuclear generating facility (MY). The NU system companies had relied on MY for approximately one percent of their capacity. During November 1997, MYAPC filed an amendment to its power contracts clarifying the obligations of its purchasing utilities following the decision to cease power production. During January 1998, the FERC accepted the amendments and proposed rates, subject to refund. At December 31, 1997, the remaining estimated obligation, including decommissioning, amounted to approximately $867.2 million, of which CL&P's share was approximately $104.0 million. On December 4, 1996, the board of directors of CYAPC voted unanimously to cease permanently the production of power at its nuclear generating plant (CY). During 1996, the NU system companies had relied on CY for approximately three percent of their capacity. During late December 1996, CYAPC filed an amendment to its power contracts clarifying the obligations of its purchasing utilities following the decision to cease power production. On February 27, 1997, the FERC approved an order for hearing which, among other things, accepted CYAPC's contract amendment. The new rates became effective March 1, 1997, subject to refund. At December 31, 1997, the remaining estimated obligation, including decommissioning, amounted to $619.9 million, of which CL&P's share was approximately $213.8 million. YAEC is in the process of decommissioning its nuclear facility. At December 31, 1997, the estimated remaining costs, including decommissioning, amounted to $124.4 million, of which CL&P's share was approximately $30.5 million. Under the terms of the contracts with MYAPC, CYAPC and YAEC, the shareholder-sponsor companies, including CL&P, are responsible for their proportionate share of the costs of the units, including decommissioning. Management expects that CL&P will continue to be allowed to recover these costs from its customers. Accordingly, CL&P has recognized these costs as regulatory assets with corresponding obligations. Proposed Accounting: The staff of the SEC has questioned certain current accounting practices of the electric utility industry, including CL&P, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating units in the financial statements. In response to these questions, the FASB has agreed to review the accounting for closure and removal costs, including decommissioning. If current electric utility industry accounting practices for nuclear power plant decommissioning are changed, the annual provision for decommissioning could increase relative to 1997, and the estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation), with recognition of an increase in the cost of the related nuclear power plant. Management believes that CL&P will continue to be allowed to recover decommissioning costs through rates. 5. SHORT-TERM DEBT Limits: The amount of short-term borrowings that may be incurred by CL&P is subject to periodic approval by either the SEC under the 1935 Act or by the DPUC. SEC authorization allowed CL&P, as of January 1, 1998, to incur total short-term borrowings up to a maximum of $375 million. Credit Agreements: In May 1997, because of the potential for NU and CL&P to violate their various financial ratio tests, NU amended the three-year revolving credit agreement (Credit Agreement) with a group of 12 banks. Under the amended Credit Agreement, CL&P and WMECO are able to borrow, subject to the availability of first mortgage bond collateral, up to $313.75 million and $150 million, respectively. At December 31, 1997, CL&P and WMECO have issued first mortgage bonds to enable borrowings under this facility up to a maximum of $225 million and $90 million, respectively. NU, which cannot issue first mortgage bonds, will be able to borrow up to $50 million if NU consolidated, CL&P and WMECO each meet certain interest coverage tests for two consecutive quarters. In addition, CL&P and WMECO each must meet certain minimum quarterly financial ratios to access the Credit Agreement. Both CL&P and WMECO satisfied these tests for the quarter ending December 31, 1997. The overall limit for all of the borrowing system companies under the entire Credit Agreement is $313.75 million. The companies are obligated to pay a facility fee of .50 percent per annum of each bank's total commitment under this Credit Agreement which will expire in November 1999. At December 31, 1997 and 1996, there were $50 million and $27.5 million, respectively, in borrowings under this Credit Agreement. Of these amounts, CL&P had $35 million borrowed in 1997 and nothing borrowed in 1996. In addition to the Credit Agreement, NU, CL&P, WMECO, HWP and RRR have various revolving credit lines through separate bilateral credit agreements. Under this facility, four banks maintain commitments to the respective companies totaling $56.25 million. NU, CL&P and WMECO may borrow up to the aggregate $56.25 million, whereas HWP and RRR may borrow up to their SEC or board authorized short-term debt limit of $5 million and $22 million, respectively. Under the terms of this facility, the companies are obligated to pay a facility fee of .15 percent per annum of each bank's total commitment. These commitments will expire in December 1998. At December 31, 1997 and 1996, there were no borrowings and $11.3 million in borrowings, respectively, under this facility, all of which had been borrowed by other NU system companies. Under the credit facilities discussed above, CL&P may borrow funds on a short-term revolving basis under its agreement, using either fixed-rate loans or standby loans. Fixed rates are set using competitive bidding. Standby loans are based upon several alternative variable rates. The weighted average annual interest rate on CL&P's notes payable to banks outstanding on December 31, 1997 was 6.95 percent. CL&P had no borrowings under these facilities at December 31, 1996. Money Pool: Certain subsidiaries of NU, including CL&P, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the system, and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate. Borrowings based on loans from NU parent, however, bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 1997, CL&P had $61.3 million of borrowings outstanding from the Pool. At December 31, 1996, CL&P had no borrowings outstanding from the Pool. The interest rate on borrowings from the Pool on December 31, 1997 was 5.8 percent. Maturities of short-term debt obligations were for periods of three months or less. For further information on short-term debt, including the ability to access these agreements, see the MD&A. 6. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION Details of preferred stock not subject to mandatory redemption are: December 31, Shares 1997 Outstanding Redemption December 31, December 31, Description Price 1997 1997 1996 1995 (Thousands of Dollars) $1.90 Series of 1947 $52.50 163,912 $ 8,196 $ 8,196 $ 8,196 $2.00 Series of 1947 54.00 336,088 16,804 16,804 16,804 $2.04 Series of 1949 52.00 100,000 5,000 5,000 5,000 $2.06 Series E of 1954 51.00 200,000 10,000 10,000 10,000 $2.09 Series F of 1955 51.00 100,000 5,000 5,000 5,000 $2.20 Series of 1949 52.50 200,000 10,000 10,000 10,000 $3.24 Series G of 1968 51.84 300,000 15,000 15,000 15,000 3.90% Series of 1949 50.50 160,000 8,000 8,000 8,000 4.50% Series of 1956 50.75 104,000 5,200 5,200 5,200 4.50% Series of 1963 50.50 160,000 8,000 8,000 8,000 4.96% Series of 1958 50.50 100,000 5,000 5,000 5,000 5.28% Series of 1967 51.43 200,000 10,000 10,000 10,000 6.56% Series of 1968 51.44 200,000 10,000 10,000 10,000 Total preferred stock not subject to mandatory redemption $116,200 $116,200 $116,200 All or any part of each outstanding series of such preferred stock may be redeemed by CL&P at any time at established redemption prices plus accrued dividends to the date of redemption. 7. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock subject to mandatory redemption are: December 31, Shares 1997 Outstanding Redemption December 31, December 31, Description Price* 1997 1997 1996 1995 (Thousands of Dollars) 7.23% Series of 1992 $52.41 1,500,000 $ 75,000 $ 75,000 $ 75,000 5.30% Series of 1993 51.00 1,600,000 80,000 80,000 80,000 155,000 155,000 155,000 Less preferred stock to be redeemed within one year......... 75,000 3,750 - - Total preferred stock subject to mandatory redemption.............. $151,250 $155,000 $155,000 *Each of these series is subject to certain refunding limitations for the first five years after they were issued. Redemption prices reduce in future years. The following table details redemption and sinking fund activity for preferred stock subject to mandatory redemption: Minimum Annual Sinking-Fund Shares Reacquired Series Requirement 1997 1996 1995 (Thousand of Dollars) 9.00% Series of 1989 $ - - - 3,000,000 7.23% Series of 1992 (1) 3,750 - - - 5.30% Series of 1993 (2) 16,000 - - - (1) Sinking fund requirements commence September 1, 1998. (2) Sinking fund requirements commence October 1, 1999. The minimum sinking-fund provisions of the series subject to mandatory redemption, for the years 1998 through 2002, aggregate approximately $3.8 million in 1998, and $19.8 million for 1999 through 2002. There were no minimum sinking-fund provisions in 1997. In case of default on sinking- fund payments, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If CL&P is in arrears in the payment of dividends on any outstanding shares of preferred stock, CL&P would be prohibited from redeeming or purchasing less than all of the preferred stock outstanding. All or part of each of the series named above may be redeemed by CL&P at any time at established redemption prices plus accrued dividends to the date of redemption, subject to certain refunding limitations. 8. LONG-TERM DEBT Details of long-term debt outstanding are: December 31, 1997 1996 (Thousands of Dollars) First Mortgage Bonds: 7 5/8% Series UU due 1997............... $ - $193,288 6 1/2% Series T due 1998............... 20,000 20,000 7 1/4% Series VV due 1999............... 99,000 99,000 5 1/2% Series A due 1999............... 140,000 140,000 5 3/4% Series XX due 2000............... 200,000 200,000 7 7/8% Series A due 2001............... 160,000 160,000 7 3/4% Series C due 2002............... 200,000 - 6 1/8% Series B due 2004............... 140,000 140,000 7 3/8% Series TT due 2019............... 20,000 20,000 7 1/2% Series YY due 2023............... 100,000 100,000 8 1/2% Series C due 2024............... 115,000 115,000 7 7/8% Series D due 2024............... 140,000 140,000 7 3/8% Series ZZ due 2025............... 125,000 125,000 Total First Mortgage Bonds......... 1,459,000 1,452,288 Pollution Control Notes: Variable rate, due 2016-2022.............. 46,400 46,400 Variable tax exempt, due 2028-2031........ 377,500 377,500 Fees and interest due for spent fuel disposal costs (Note 2M)............. 166,458 157,968 Other....................................... 86 10,915 Less amounts due within one year............ 20,011 204,116 Unamortized premium and discount, net....... (6,117) (6,550) Long-term debt, net....................... $2,023,316 $1,834,405 Long-term debt and cash sinking-fund requirements on debt outstanding at December 31, 1997 for the years 1998 through 2002 are approximately $20.0 million, $239.0 million, $200.0 million, $160.0 million and $200.0 million, respectively. The one-percent sinking- and improvement-fund requirements for CL&P first mortgage bonds are no longer required, as of 1997, as determined by a majority of bondholders. All or any part of each outstanding series of first mortgage bonds may be redeemed by CL&P at any time at established redemption prices plus accrued interest to the date of redemption, except certain series which are subject to certain refunding limitations during their respective initial five-year redemption periods. Essentially all of CL&P's utility plant is subject to the lien of its first mortgage bond indenture. As of December 31, 1997 and 1996, CL&P has secured $315.5 million of pollution control notes with second mortgage liens on Millstone 1, junior to the lien of its first mortgage bond indenture. The average effective interest rate on the variable-rate pollution control notes ranged from 3.6 percent to 3.7 percent for 1997 and from 3.4 percent to 3.6 percent for 1996. CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds with a bond insurance and liquidity facility secured by First Mortgage Bonds. 9. INCOME TAX EXPENSE The components of the federal and state income tax provisions (credited)/ charged to operations are: For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) (Thousands of Dollars) Current income taxes: Federal..................... $(53,339) $30,650 $ 93,906 State....................... (3,270) 9,789 37,898 Total current............. (56,609) 40,439 131,804 Deferred income taxes, net: Federal..................... 8,436 (22,866) 52,075 State....................... (11,470) (9,409) 5,085 Total deferred............ (3,034) (32,275) 57,160 Investment tax credits, net... (7,366) (7,367) (7,640) Total income tax (credit)/expense.......... $(67,009) $ 797 $181,324 The components of total income tax expense are classified as follows: Income taxes charged to operating expenses.......... $(59,436) $ 957 $178,346 Other income taxes............ (7,573) (160) 2,978 Total income tax (credit)/expense............... $(67,009) $ 797 $181,324 Deferred income taxes are comprised of the tax effects of temporary differences as follows: For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) (Thousands of Dollars) Depreciation, leased nuclear fuel, settlement credits and disposal costs.................. $ 11,991 $ 3,981 $ 44,278 Energy adjustment clauses......... (14,039) (1,654) 23,302 Demand-side management............ (12,408) (17,099) 1,310 Nuclear plant deferrals........... 14,007 (18,861) (8,055) Bond redemptions.................. (1,339) (1,789) (2,255) Contractual settlements........... 1,754 2,513 (9,496) Pension accruals.................. 6,524 2,944 5,382 State net operating loss carryforwards................... (7,670) - - Other............................. (1,854) (2,310) 2,694 Deferred income taxes, net........ $ (3,034) $(32,275) $ 57,160 A reconciliation between income tax expense and the expected tax expense at the applicable statutory rate is as follows: For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) (Thousands of Dollars) Expected federal income tax at 35 percent of pretax income..... $(72,312) $(18,257) $135,289 Tax effect of differences: State income taxes, net of federal benefit............... (8,966) 248 27,939 Depreciation.................... 19,701 21,313 23,517 Deferred nuclear plants return.. (30) (444) (1,639) Amortization of regulatory assets ............ 3,901 8,601 20,218 Property tax.................... - - (159) Investment tax credit amortization.................. (7,366) (7,367) (7,640) Adjustment for prior years' taxes......................... (10) - (10,442) Other, net...................... (1,927) (3,297) (5,759) Total income tax (credits)/expense............... $(67,009) $ 797 $181,324 10. EMPLOYEE BENEFITS A. PENSION BENEFITS The NU system's subsidiaries participate in a uniform noncontributory defined benefit retirement plan covering all regular NU system employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. CL&P's direct portion of the NU system's pension credit, part of which was credited to utility plant, approximated $22.5 million in 1997, $8.8 million in 1996 and $10.4 million in 1995. The company's pension (credit)/costs for 1997, 1996 and 1995 included approximately $(949) thousand, $2.8 million and $0.1 million, respectively, related to workforce reduction programs. Currently, CL&P annually funds an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code. Pension costs are determined using market-related values of pension assets. Pension assets are invested primarily in domestic and international equity securities and bonds. The components of net pension credit for CL&P are: For the Years Ended December 31, 1997 1996 1995 (Thousands of Dollars) Service cost................... $ 7,888 $ 11,896 $ 7,543 Interest cost.................. 37,939 37,226 37,110 Return on plan assets.......... (148,830) (103,248) (138,582) Net amortization............... 80,507 45,300 83,516 Net pension credit............. $(22,496) $ (8,826) $(10,413) For calculating pension cost, the following assumptions were used: For the Years Ended December 31, 1997 1996 1995 Discount rate................. 7.75% 7.50% 8.25% Expected long-term rate of return.............. 9.25 8.75 8.50 Compensation/progression rate........................ 4.75 4.75 5.00 The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: At December 31, 1997 1996 (Thousands of Dollars) Accumulated benefit obligation, including vested benefits at December 31, 1997 and 1996 of $(420,499,000) and $(405,340,000), respectively........................ $(451,802) $(434,473) Projected benefit obligation.......... $(531,564) $(514,989) Market value of plan assets........... 846,366 736,448 Market value in excess of projected benefit obligation.................. 314,802 221,459 Unrecognized transition amount........ (6,445) (7,365) Unrecognized prior service costs...... 3,524 3,818 Unrecognized net gain................. (269,560) (198,088 Prepaid pension asset................. $ 42,321 $ 19,824 The following actuarial assumptions were used in calculating the plan's year-end funded status: At December 31, 1997 1996 Discount rate......................... 7.25% 7.75% Compensation/progression rate......... 4.25 4.75 B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS The NU system's subsidiaries provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (referred to as SFAS 106 benefits). These benefits are available for employees retiring from the NU system who have met specified service requirements. For current employees and certain retirees, the total SFAS 106 benefit is limited to two times the 1993 per-retiree health care cost. The SFAS 106 obligation has been calculated based on this assumption. CL&P's direct portion of SFAS 106 costs, part of which were deferred or charged to utility plant, approximated $12.8 million in 1997, $17.9 million in 1996 and $20.7 million in 1995. During 1997 and 1996, CL&P funded SFAS 106 postretirement costs through external trusts. CL&P is funding, on an annual basis, amounts that have been rate-recovered and which also are tax deductible under the Internal Revenue Code. The trust assets are invested primarily in equity securities and bonds. The components of health care and life insurance cost are: For the Years Ended December 31, 1997 1996 1995 (Thousands of Dollars) Service cost ...................... $ 1,692 $ 2,270 $ 2,248 Interest cost ..................... 9,152 10,211 11,510 Return on plan assets ............. (7,755) (2,904) (1,015) Amortization of unrecognized transition obligation ........... 7,344 7,344 7,344 Other amortization, net ........... 2,370 956 602 Net health care and life insurance cost .................. $12,803 $17,877 $20,689 For calculating SFAS 106 benefit costs, the following assumptions were used: For the Years Ended December 31, 1997 1996 1995 Discount rate ..................... 7.75% 7.50% 8.00% Long-term rate of return - Health assets, net of tax ....... 6.00 5.25 5.00 Life assets ..................... 9.25 8.75 8.50 The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: At December 31, 1997 1996 (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees ............................ $(102,282) $(109,299) Fully eligible active employees ..... (219) (165) Active employees not eligible to retire ......................... (24,075) (27,913) Total accumulated postretirement benefit obligation ................. (126,576) (137,377) Market value of plan assets .......... 46,055 38,783 Accumulated postretirement benefit obligation in excess of plan assets ........................ (80,521) (98,594) Unrecognized transition amount ....... 110,162 117,506 Unrecognized net gain ................ (29,641) (18,912) Accrued postretirement benefit liability .......................... $ - $ - The following actuarial assumptions were used in calculating the plan's year-end funded status: At December 31, 1997 1996 Discount rate ........................ 7.25% 7.75% Health care cost trend rate (a) ...... 5.76 7.23 (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 4.40 percent by 2001. The effect of increasing the assumed health care cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1997, by $7.3 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $563 thousand. The trust holding the health plan assets is subject to federal income taxes at a 39.6 percent tax rate. CL&P currently is recovering SFAS 106 costs through rates. 11. SALE OF CUSTOMER RECEIVABLES AND ACCRUED UTILITY REVENUES During 1996, CL&P entered into an agreement to sell up to $200 million of undivided ownership interests in eligible customer receivables and accrued utility revenues (receivables). The FASB issued SFAS 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," in June 1996. SFAS 125 became effective on January 1, 1997, and establishes, in part, criteria for concluding whether a transfer of financial assets in exchange for consideration should be accounted for as a sale or as a secured borrowing. During October 1997, CL&P restructured its sales agreement to comply with the conditions of SFAS 125 and account for transactions occurring under this program as sales of assets. CL&P has established a special purpose, wholly owned subsidiary whose business consists of the purchase and resale of receivables. For receivables sold, CL&P has retained collection responsibilities as agent for the purchaser under CL&P's agreement. As collections reduce previously sold receivables, new receivables may be sold. At December 31, 1997, approximately $70 million of receivables had been sold to a third-party purchaser by CL&P through the use of CL&P's special purpose, wholly owned subsidiary, CL&P Receivables Corporation (CRC). All receivables transferred to CRC are assets owned by CRC and are not available to pay CL&P's creditors. For CRC's sales agreement with its third-party purchaser, the receivables are sold with limited recourse. CRC's sales agreement provides for a formula-based loss reserve in which additional receivables may be assigned to the third-party purchaser for costs such as bad debt. The third-party purchaser absorbs the excess amount in the event that actual loss experience exceeds the loss reserve. At December 31, 1997, approximately $7.2 million of assets had been designated as collateral by CRC. This amount represents the formula-based amount of credit exposure at December 31, 1997. Historical losses for bad debt for CL&P have been substantially less. CL&P's accounts receivable program could be terminated if its senior secured debt is downgraded two more steps from its current ratings. Concentrations of credit risk to the purchaser under the company's agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. For additional information on the accounts receivable program and CL&P's ability to utilize this program, see the MD&A. 12. COMMITMENTS AND CONTINGENCIES A. RESTRUCTURING AND RATE MATTERS Although CL&P continues to operate under cost-of-service based regulation, legislative restructuring initiatives during 1997 and 1998 in its jurisdiction has created some uncertainty with respect to future rates and the recovery of strandable investments and certain future costs such as purchase power obligations. Management is unable to predict the ultimate outcome of restructuring initiatives, however, it continues to believe that it is probable that CL&P will fully recover its prudently incurred costs, including regulatory assets and strandable investments based on the general nature of public utility cost-of-service regulation. For further information on restructuring, see Note 2H, "Summary of Significant Accounting Policies - Regulatory Accounting and Assets," and the MD&A. The DPUC is required to review a utility's rates every four years if there had not been a rate proceeding during such period. The DPUC has conducted such a review. For information regarding this review and other rate matters, see the MD&A. For information regarding the FERC rate proceedings for CYAPC and MYAPC, see Note 4, "Nuclear Decommissioning." B. NUCLEAR PERFORMANCE Millstone: The three Millstone units are managed by NNECO. Millstone 1, 2 and 3 have been out of service since November 4, 1995, February 21, 1996, and March 30, 1996, respectively, and are on the Nuclear Regulatory Commission's (NRC) watch list. NU has restructured its nuclear organization and is currently implementing comprehensive plans to restart the units. Subsequent to its January 31, 1996 announcement that Millstone had been placed on its watch list, the NRC stated that the units cannot return to service until independent, third-party verification teams have reviewed the actions taken to improve the design, configuration and employee concerns issues that prompted the NRC to place the units on its watch list. The actual date of the return to service for each of the units is dependent upon the completion of independent inspections and reviews by the NRC and a vote by the NRC commissioners. NU hopes to return Millstone 3 to service in the early spring of 1998 and Millstone 2 three to four months after Millstone 3. Millstone 1 is currently in extended maintenance status. Management cannot predict when the NRC will allow any of the Millstone units to return to service and thus cannot precisely estimate the total replacement power costs CL&P will ultimately incur. Replacement power costs incurred by CL&P attributable to the Millstone outages averaged approximately $23 million per month during 1997, and for 1998 are projected to average approximately $7 million per month for Millstone 3, $7 million per month for Millstone 2 and $5 million per month for Millstone 1 while the plants remain out of service. CL&P will continue to expense its replacement power costs in 1998. Based on the current estimates of expenditures and restart dates, management believes the NU system has sufficient resources to fund the restoration of the Millstone units and related replacement power costs. If the return to service of Millstone 3 or 2 is delayed substantially beyond the present restart estimates, if some financing facilities become unavailable because of difficulties in meeting borrowing conditions or renegotiating extensions, if CL&P and WMECO encounter additional significant costs or if any other significant deviations from management's assumptions occur, CL&P and WMECO could be unable to meet their cash requirements. In those circumstances, management would take even more stringent actions to reduce costs and cash outflows and attempt to obtain additional sources of funds. The availability of these funds would be dependent upon general market conditions and CL&P's and WMECO's respective credit and financial conditions at that time. For information regarding Millstone restart costs, see the MD&A. For information concerning the ability of CL&P to access its borrowing facilities, see the MD&A. Litigation: CL&P and WMECO, through NNECO as agent, operate Millstone 3 at cost, and without profit, under a sharing agreement that obligates them to utilize good utility operating practice and requires the joint owners to share the risk of employee negligence and other risks of operation and maintenance pro-rata in accordance with their ownership shares. This agreement also provides that CL&P and WMECO would be liable only for damages to the non-NU owners for a deliberate violation of the agreement pursuant to authorized corporate action. On August 7, 1997, the non-NU owners of Millstone 3 filed demands for arbitration with CL&P and WMECO as well as lawsuits in Massachusetts Superior Court against NU and its current and former trustees. The non-NU owners raise a number of contract, tort and statutory claims arising out of the operation of Millstone 3. The arbitrations and lawsuits seek to recover compensatory damages, punitive damages, treble damages and attorneys' fees. Owners representing approximately two- thirds of the non-NU interests in Millstone 3 claimed compensatory damages in excess of $200 million. In addition, one of the lawsuits seeks to restrain NU from disposing of its shares of the stock of WMECO and HWP, pending the outcome of the lawsuit. Management cannot estimate the potential outcome of these suits but believes there is no legal basis for the claims and intends to defend against them vigorously. To date, no reserves have been established for this litigation. At December 31, 1997, the NU system's costs related to this litigation were estimated to be approximately $100 million for incremental O&M costs and approximately $100 million for replacement power costs. These costs are likely to increase as long as Millstone 3 remains out of service. The Connecticut Municipal Electric Energy Cooperative (CMEEC) and CL&P have been negotiating since May 1996 over issues related to the operation of Millstone 1 and 2. CMEEC has failed to make payments on its accrued obligations since October 1996, claiming that CL&P materially breached its contractual obligations. CL&P has denied the allegations and requested payment. The matter has gone to arbitration which has been scheduled for July 1998. CL&P has filed an application with the Connecticut Superior Court in Hartford requesting the court to grant interim relief to CL&P. CL&P has asked the court to enforce the contract provisions by ordering CMEEC to pay the outstanding obligations under the contract (approximately $25 million) and to continue making payments (approximately $1.8 million per month) during the arbitration process. On December 9, 1997, the Superior Court judge issued a decision denying CL&P's request for an interim payment order. Management cannot predict the outcome of this litigation and has taken steps to assert its legal rights. CL&P has requested reargument, in order to present evidence, and has requested that the Connecticut Superior Court vacate its order. CL&P is prepared to appeal to a higher court, if necessary, after the reargument. C. ENVIRONMENTAL MATTERS The NU system is subject to regulation by federal, state and local authorities with respect to air and water quality, the handling and disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. The NU system has an active environmental auditing and training program and believes that it is in substantial compliance with current environmental laws and regulations. However, the NU system is subject to certain pending enforcement actions and governmental investigations in the environmental area. Management cannot predict the outcome of these enforcement actions and investigations. Environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations and other facilities. Changing environmental requirements could also require extensive and costly modifications to CL&P's existing generating units and transmission and distribution systems, and could raise operating costs significantly. As a result, CL&P may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation and transmission of electricity and the storage, transportation and disposal of byproducts and wastes. CL&P may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. The cumulative long-term cost impact of increasingly stringent environmental requirements cannot be estimated accurately. CL&P has recorded a liability based upon currently available information for what it believes are its estimated environmental remediation costs that it expects to incur for waste disposal sites. In most cases, additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation and the possible effects of technological changes. At December 31, 1997, the net liability recorded by CL&P for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $6.4 million, which management has determined to be the most probable amount within the range of $6.4 million to $16.4 million. During 1997, CL&P adopted Statement of Position 96-1, "Environmental Remediation Liabilities" (SOP). The principal objective of the SOP is to improve the manner in which existing authoritative accounting literature is applied by entities to specific situations of recognizing, measuring and disclosing environmental remediation liabilities. The adoption of the SOP resulted in an increase of approximately $395 thousand to CL&P's environmental reserve in 1997. CL&P cannot estimate the potential liability for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws and regulatory practices, management does not believe the matters disclosed above will have a material effect on CL&P's financial position or future results of operations. D. NUCLEAR INSURANCE CONTINGENCIES Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities in the country covered by the federal government's third-party liability indemnification program, an owner of a nuclear unit could be assessed in proportion to its ownership interest in each of its nuclear units up to $75.5 million. Payments of this assessment would be limited to $10.0 million in any one year per nuclear incident based upon the owner's pro rata ownership interest in each of its nuclear units. In addition, the owner would be subject to an additional five percent or $3.8 million, in proportion to its ownership interests in each of its nuclear units, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection. Based upon its ownership interests in Millstone 1, 2 and 3 and in Seabrook 1, CL&P's maximum liability, including any additional assessments, would be $173.6 million per incident, of which payments would be limited to $21.9 million per year. In addition, through power purchase contracts with MYAPC, VYNPC, and CYAPC, CL&P would be responsible for up to an additional $44.4 million per incident, of which payments would be limited to $5.6 million per year. Insurance has been purchased to cover the primary cost of repair, replacement or decontamination of utility property resulting from insured occurrences. CL&P is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessment against CL&P with respect to losses arising during the current policy year is approximately $11.5 million under the primary property insurance program. Insurance has been purchased to cover certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement or decontamination or premature decommissioning of utility property resulting from insured occurrences. CL&P is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessments against CL&P with respect to losses arising during current policy years are approximately $9.5 million under the replacement power policies and $15.6 million under the excess property damage, decontamination and decommissioning policies. The cost of a nuclear incident could exceed available insurance proceeds. Insurance has been purchased aggregating $200 million on an industry basis for coverage of worker claims. All participating reactor operators insured under this coverage are subject to retrospective assessments of $3 million per reactor. The maximum potential assessment against CL&P with respect to losses arising during the current policy period is approximately $8.9 million. Effective January 1, 1998, a new worker policy was purchased which is not subject to retrospective assessments. E. CONSTRUCTION PROGRAM The construction program is subject to periodic review and revision by management. CL&P currently forecasts construction expenditures of approximately $1.3 billion for the years 1998-2002, including $164.9 million for 1998. In addition, CL&P estimates that nuclear fuel requirements, including nuclear fuel financed through the NBFT, will be approximately $247.7 million for the years 1998-2002, including $37.6 million for 1998. See Note 3, "Leases," for additional information about the financing of nuclear fuel. F. LONG-TERM CONTRACTUAL ARRANGEMENTS Yankee Companies: CL&P, WMECO and PSNH rely on VY for approximately 1.7 percent of their capacity under long-term contracts. Under the terms of their agreements, the NU system companies pay their ownership (or entitlement) shares of costs which include depreciation, O&M expenses, taxes, the estimated cost of decommissioning and a return on invested capital. These costs are recorded as purchased power expense and are recovered through the company's rates. CL&P's total cost of purchases under contracts with VYNPC amounted to $14.1 million in 1997, $14.8 million in 1996 and $14.7 million in 1995. The other Yankee generating facilities, MY, CY and Yankee Rowe, were permanently shutdown as of August 6, 1997, December 4, 1996 and February 26, 1992, respectively. See Note 2E, "Summary of Significant Accounting Policies - Investments and Jointly Owned Electric Utility Plant," for further information on the Yankee companies, and Note 4, "Nuclear Decommissioning," regarding the related decommissioning obligations. Nonutility Generators: CL&P has entered into various arrangements for the purchase of capacity and energy from nonutility generators (NUGs). These arrangements have terms from 10 to 30 years, currently expiring in the years 2001 through 2028, and require CL&P to purchase energy at specified prices or formula rates. For the 12-month period ending December 31, 1997, approximately 14 percent of NU system electricity requirements was met by NUGs. CL&P's total cost of purchases under these arrangements amounted to $283.2 million in 1997, $279.5 million in 1996 and $282.2 million in 1995. These costs may be deferred for eventual recovery through rates. Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO and HWP have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M and capital costs of these facilities. Estimated Annual Costs: The estimated annual costs of CL&P's significant long-term contractual arrangements are as follows: 1998 1999 2000 2001 2002 (Millions of Dollars) VYNPC ............. $ 16.8 $ 16.9 $ 16.2 $ 17.7 $ 18.4 NUGs ............. 281.0 291.5 290.9 295.5 299.6 Hydro-Quebec ...... 18.5 17.9 17.6 17.1 16.7 For additional information regarding the recovery of purchased power costs, see Note 2J, "Summary of Significant Accounting Policies - Recoverable Energy Costs." 13. MARKET RISK MANAGEMENT CL&P uses swap, collar, put and call instruments with financial institutions to hedge against some of the fuel price risk created by long- term negotiated energy contracts and nuclear replacement power generation and fuel purchases. These agreements minimize exposure associated with rising fuel prices by managing a portion of CL&P's cost of fuel for these negotiated energy contracts and nuclear replacement power generation and fuel purchases. As of December 31, 1997, CL&P had outstanding agreements with a total notional value of approximately $327 million, and a negative mark-to-market position of approximately $21 million. The terms of the agreements require CL&P to post cash collateral with its counterparties in the event of negative mark-to-market positions and lowered credit ratings. The amount of the collateral is to be returned to CL&P when the mark-to-market position becomes positive, when CL&P meets specified credit ratings or when an agreement ends and all open positions are properly settled. At December 31, 1997, cash collateral in the amount of $15.4 million was posted under these terms, which is included in other, at cost, on the accompanying Consolidated Balance Sheets. These agreements have been made with various financial institutions, each of which is rated "A1" or better by Moody's rating group. CL&P will be exposed to credit risk on its fuel price management instruments if the counterparties fail to perform their obligations. However, management anticipates that the counterparties will be able to fully satisfy their obligations under the agreements. 14. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY CL&P Capital LP (CL&P LP, a subsidiary of CL&P) had previously issued $100 million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS), Series A. CL&P has the sole ownership interest in CL&P LP, as a general partner, and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance, CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million capital contribution, back to CL&P in the form of an unsecured debenture. CL&P consolidates CL&P LP for financial reporting purposes. Upon consolidation, the unsecured debenture is eliminated and the MIPS securities are accounted for as minority interests. 15. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and nuclear decommissioning trusts: The carrying amounts approximate fair value. SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," requires investments in debt and equity securities to be presented at fair value. As a result of this requirement, the investments held in CL&P's nuclear decommissioning trusts were adjusted to market by approximately $49.2 million as of December 31, 1997, and $22.3 million as of December 31, 1996, with corresponding offsets to the accumulated provision for depreciation. The amounts adjusted in 1997 and 1996 represent cumulative gross unrealized holding gains. The cumulative gross unrealized holding losses were immaterial for both 1997 and 1996. Preferred stock and long-term debt: The fair value of CL&P's fixed rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of CL&P's financial instruments and the estimated fair values are as follows: Carrying Fair At December 31, 1997 Amount Value (Thousands of Dollars) Preferred stock not subject to mandatory redemption..................... $ 116,200 $ 62,889 Preferred stock subject to mandatory redemption........................ 155,000 135,600 Long-term debt - First Mortgage Bonds........................ 1,459,000 1,435,772 Other long-term debt........................ 590,443 590,443 MIPS.......................................... 100,000 100,760 Carrying Fair At December 31, 1996 Amount Value (Thousands of Dollars) Preferred stock not subject to mandatory redemption...................... $ 116,200 $ 111,845 Preferred stock subject to mandatory redemption......................... 155,000 120,900 Long-term debt - First Mortgage Bonds......................... 1,452,288 1,410,665 Other long-term debt......................... 592,783 592,783 MIPS ............................................ 100,000 108,520 The fair values shown above have been reported to meet disclosure requirements and do not purport to represent the amounts at which those obligations would be settled. The Connecticut Light and Power Company and Subsidiaries REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of The Connecticut Light and Power Company: We have audited the accompanying consolidated balance sheets, as restated - see Note 1, of The Connecticut Light and Power Company and Subsidiaries (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31, 1997 and 1996, and the related consolidated statements of income, common stockholder's equity and cash flows, as restated - see Note 1, for each of the three years in the period ended December 31, 1997. 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 Connecticut Light and Power Company and Subsidiaries as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. As explained in Note 1 to the consolidated financial statements, the company has given retroactive effect to the change in accounting for nuclear compliance costs. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 20, 1998 (except with respect to the matter discussed in Note 1, as to which the date is June 10, 1998). THE CONNECTICUT LIGHT AND POWER COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This section contains management's assessment of CL&P's (the company) financial condition and the principal factors having an impact on the results of operations. The company is a wholly-owned subsidiary of Northeast Utilities (NU). This discussion should be read in conjunction with the company's consolidated financial statements and footnotes. FINANCIAL CONDITION OVERVIEW The length of the ongoing outages at the three Millstone nuclear plants (Millstone) and the high costs of the recovery efforts weakened CL&P's 1997 net income, balance sheet and cash flows and will continue to have an adverse impact on the company's financial condition until the units are returned to service. CL&P had a net loss of approximately $140 million in 1997, compared to a net loss of approximately $51 million in 1996. The poorer financial results in 1997 were due primarily to the fact that all three Millstone units were off line for the entire year in 1997 and spending associated with the recovery efforts was significantly higher in 1997 than it was in 1996. Millstone 3 operated for nearly three months in 1996 and Millstone 2 for nearly two months. As a result, the cost of replacing power ordinarily generated by the Millstone units rose by approximately $65 million in 1997. The total operation and maintenance (O&M) costs at Millstone were approximately $173 million higher in 1997. The higher Millstone costs have caused CL&P to focus closely on maintaining adequate liquidity and reducing nonnuclear O&M costs. In June 1997, CL&P successfully sold $200 million in first mortgage bonds. CL&P's access to $225 million of revolving credit lines was renegotiated in the first half of 1997. Also helping to maintain liquidity was the renegotiation in early 1998 of a $100 million credit line used by Niantic Bay Fuel Trust (NBFT) to purchase nuclear fuel for Millstone. Additionally, nonnuclear O&M expenses in 1997 were reduced by about $30 million from 1996. The SEC has advised CL&P to adjust for certain costs associated with the ongoing Millstone outages as they are incurred. For the past two years, CL&P has been reserving for the unavoidable costs they expected to incur to meet NRC requirements. These annual statements have been adjusted in accordance with the SEC's directive. Management does not expect implementation of this accounting change to affect the ability of CL&P and Western Massachusetts Electric Company (WMECO) to meet their financial covenants contained in their $313.75 million revolving credit arrangement. In 1998, management expects Millstone-related expenses to fall significantly, assuming Millstone 3 and Millstone 2 are returned to service at dates close to current estimates, although the O&M expenses at Millstone 3 and 2 will be considerably higher than before the station was placed on the Nuclear Regulatory Commission's (NRC's) watch list. The actual level of 1998 nuclear spending at Millstone will depend on when the units return to operation and the cost of restoring them to service. The company hopes to restart Millstone 3, the newest and largest unit at the site, in the early spring of 1998 and Millstone 2 three to four months after Millstone 3. The company cannot restart the Millstone units until it receives formal approval from the NRC. As part of an effort to reduce spending in 1998, Millstone 1 has been placed in extended maintenance status. Management will review its options with respect to Millstone 1 in 1998, including restart, early retirement and other options. Rate reductions to customers served by CL&P are likely to offset a portion of the benefit of lower Millstone-related costs. On March 1, 1998, CL&P's rates were reduced by approximately 1.4 percent to reflect the removal of Millstone 1 from rates, and additional non cash reductions were made to revenue requirements as a result of an interim rate order issued by the Connecticut Department of Public Utility Control (DPUC). A pending CL&P rate case may result in additional rate adjustments later in 1998. CL&P's revenues could be further reduced if substantial delays in restarting Millstone 3 and Millstone 2 result in a DPUC decision to remove those units from rates. In addition to focusing on maintaining liquidity, management also must attend to industry restructuring efforts in Connecticut. Restructuring legislation is being considered in the Connecticut legislative session that began in February 1998. In 1997, CL&P experienced modest economic growth in its retail sales that was offset by the effects of mild winter weather. In 1998, management expects that the Connecticut economy will continue to experience modest growth. MILLSTONE OUTAGES CL&P has an 81-percent ownership interest in Millstone units 1 and 2 and a 52.93-percent ownership interest in Millstone unit 3. Millstone 1, 2 and 3 have been out of service since November 4, 1995, February 21, 1996, and March 30, 1996, respectively. Subsequent to its January 31, 1996, announcement that Millstone had been placed on its watch list, the NRC has stated that the units cannot return to service until independent, third-party verification teams have reviewed the actions taken to improve the design, configuration and employee concern issues that prompted the NRC to place the units on its watch list. The actual date of the return to service for each of the units is dependent upon the completion of independent inspections, reviews by the NRC and a vote by the NRC Commissioners. In January 1998, NU declared Millstone 3 physically ready for restart, which meant that almost all of the restart-required physical work had been completed in the plant. The NRC currently is conducting a series of inspections to determine, among other things, whether the plant has effective leadership and corrective action and employee concerns programs. The Independent Corrective Action Verification Program, an NRC-ordered independent review of the plant's design and licensing bases, is expected to be completed in March 1998. In 1997, CL&P's share of nonfuel O&M costs expensed for Millstone increased to approximately $445 million, compared to approximately $272 million in 1996. CL&P's portion of replacement power costs attributable to the Millstone outages totaled approximately $281 million in 1997 compared to $216 million expensed in 1996. These costs for 1998 are forecasted to average approximately $7 million per month for Millstone 3, $7 million per month for Millstone 2 and $5 million per month for Millstone 1 while the plants are out of service. CL&P has been, and will continue to be, expensing all of the costs to restart the units including replacement power and nonfuel O&M expenses. See "Rate Matters" for issues related to the recovery of Millstone 1 costs. NU and its subsidiaries are involved in several class action lawsuits and other litigation in connection with their nuclear operations. See the "Notes to Consolidated Financial Statements," Note 12B, for further information on this litigation. MILLSTONE 1 Management will review its options with respect to Millstone 1 during 1998. The issues that management will consider in evaluating its options include the costs to restart the unit, the economic benefits of the unit's continued operation and certain Connecticut state law issues. In the CL&P four year rate review proceeding, (discussed in detail under "Rate Matters"), the DPUC noted that CL&P may not be able to recover its remaining investment in Millstone 1 if the DPUC were to determine that the unit had been prematurely shut down due to management imprudence. Additionally, there is a Connecticut statute which may limit CL&P's ability to collect decommissioning charges in the future if Millstone 1 were to be prematurely retired. CL&P's net unrecovered Millstone 1 plant cost and the unrecovered decommissioning costs at December 31, 1997, were approximately $216 million and $198 million, respectively. CAPACITY During 1996 and continuing into 1997, CL&P took measures to improve its capacity position, including obtaining additional generating capacity, improving the availability of CL&P's generating units and improving its transmission capability. During 1997, CL&P spent approximately $48 million to ensure availability in Connecticut of adequate generating capacity in Connecticut, of which $35 million was expensed. During 1998 these costs are expected to be approximately $11 million.(DO WE WANT TO SAY WHY 1998 IS SO MUCH LOWER )In 1998, CL&P does not anticipate the need to take additional measures to ensure adequate generating capacity. CL&P could incur up to an additional $50 million in 1998 for incremental capacity purchases to meet NEPOOL requirements as a result of the Millstone outages. LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations decreased approximately $227 million in 1997, compared to 1996, primarily due to higher cash expenditures related to the Millstone outages, and the pay down in 1997 of the 1996 year end accounts payable balance. The 1996 year end accounts payable balance was relatively high due to costs related to a severe December storm and costs associated with the Millstone outages that had been incurred but not yet paid by the end of 1996. Net cash from financing activities increased approximately $69 million, primarily due to an increase in short-term borrowings and lower cash dividends on common shares, partially offset by higher long-term debt retirements. Cash used for investments decreased approximately $158 million, primarily due to lower investments in the NU system Money Pool, partially offset by higher capital expenditures and an increase in special deposits. CL&P established facilities in 1996 under which it may sell, from time to time, up to $200 million of its accounts receivable and accrued utility revenues. As of December 31, 1997, CL&P sold approximately $70 million of receivables to third-party purchasers. NU's, CL&P's and WMECO's three-year revolving credit agreement (Credit Agreement) was amended in May 1997 (the Credit Agreement). Under the Revolving Credit Agreement, CL&P and WMECO are able to borrow up to approximately $225 million and $90 million, respectively, subject to a total borrowing limit of $313.75 million for all three borrowers. NU will be able to borrow up to $50 million when NU, CL&P and WMECO have each maintained a consolidated operating income to consolidated interest expense ratio of at least 2.50 to 1 for two consecutive fiscal quarters. Currently, the companies cannot meet this requirement. At December 31, 1997, CL&P had $35 million outstanding under the New Credit Agreement. Each major subsidiary of NU finances its own needs. Neither CL&P nor WMECO has any financing agreements containing cross defaults based on financial defaults by NU, Public Service Company of New Hampshire (PSNH) or North Atlantic Energy Corporation (NAEC). Nevertheless, it is possible that investors will take negative operating results or regulatory developments for one subsidiary of NU into account when evaluating the other NU subsidiaries. That could, as a practical matter and despite the contractual and legal separations among NU and its subsidiaries, negatively affect the company's access to financial markets. In December 1997 and January 1998, Moody's Investors Service (Moody's) and Standard & Poor's (S&P), respectively, downgraded the senior secured debt of CL&P, WMECO and NU, as well as the preferred stock of CL&P and WMECO. This was the fourth time Moody's and S&P have downgraded CL&P and WMECO securities since the Millstone units went on the NRC watch list in 1996. All of NU system's securities are rated below investment grade and remain under review for further downgrade. CL&P's accounts receivable program could be terminated if its senior secured debt is downgraded two more steps from its current ratings. Although CL&P does not have any plans to issue debt in the near term, rating agency downgrades generally increase the future cost of borrowing funds because lenders will want to be compensated for increased risk. Additionally, this could affect the terms and ability of the company to extend existing agreements. CL&P's ability to borrow under the financing arrangements is dependent on the satisfaction of contractual borrowing conditions. The financial covenants that must be satisfied to permit CL&P and WMECO to borrow under the New Credit Agreement are particularly restrictive and become more restrictive throughout 1998. Spending levels in 1998, particularly for the first half of the year while the Millstone units are expected to be out of service, will be constrained to levels intended to assure that the financial covenants in CL&P's and WMECO's Credit Agreement are satisfied. However, there is no assurance that these financial covenants will be met as the system may encounter additional unexpected costs from such areas as storms, reduced revenues from regulatory actions or the effect of weather on sales levels. If the return to service of Millstone 3 or Millstone 2 is delayed substantially beyond the present restart estimates, if some borrowing facilities become unavailable because of difficulties in meeting borrowing conditions or renegotiating extensions, if the system encounters additional significant costs, or any other significant deviations from management's current assumptions, the currently available borrowing facilities could be insufficient to meet all of CL&P's cash requirements. In those circumstances, management would take even more stringent actions to reduce costs and cash outflows and would attempt to take other actions to obtain additional sources of funds. The availability of these funds would be dependent upon the general market conditions and CL&P's credit and financial condition at that time. RESTRUCTURING CL&P continues to operate under cost-of-service based regulation, however, future rates and the recovery of strandable costsinvestments are issues that are being considered as part of broad restructuring legislation in the current Connecticut legislative session. Strandable costs are expenditures or commitments that have been made to meet public service obligations with the expectation that they would be recovered from customers in the future. CL&P has has exposure to strandable costs for itsits investments in high-cost nuclear generating plants, state-mandated purchased power obligations and significant regulatory assets. The company's exposure to strandable investments and purchased power obligations exceeds its shareholder's equity. CL&P's financial strength and resulting ability to compete in a restructured environment will be negatively affected if the company is unable to recover its past investments and commitments. Even if the company is given the opportunity to recover a large portion of its strandable costs, earnings prospects in a restructured environment will be affected in ways which cannot be estimated at this time. The company is seeking to mitigate the impacts of restructuring by proposing stable, lower rates, while pursuing customer choice options and full recovery of itsits strandable costsinvestments. The company's strategy to recover strandable costsinvestments includes efforts to promote state legislation that will authorize the issuance of rate reduction bonds that would refinance these investments and which would be repaid through non-bypassable charges to customers. Management is unable to predict the ultimate outcome of these initiatives which will be subject to regulatory and legislative approvals. Management believes it is entitled to full recovery of its prudently incurred costs, including regulatory assets and other strandable costs. See the "Notes to Consolidated Financial Statements," Note 2H, for the potential accounting impacts of restructuring. RATE MATTERS In July 1996, the DPUC approved a rate settlement agreement with CL&P (the Settlement). Under the Settlement, CL&P froze base rates until at least December 31, 1997, and agreed to accelerate the amortization of regulatory assets during the period that the rate freeze remains in effect. The Settlement provided that CL&P's target return on equity (ROE) would be 10.7 percent but did not alter CL&P's allowed ROE of 11.7 percent. If CL&P's actual ROE for a calendar year exceeds 10.7 percent after the target regulatory asset amortization ($68 million in 1997) and after adjustment for any incremental NRC billings and any rate disallowances for nuclear operations, then CL&P shall retain two-thirds of any surplus and use the remaining one-third to provide a reduction in bills. CL&P's actual ROE, as adjusted, fell below the target ROE for 1996 and 1997 and, therefore, the accelerated amortization of regulatory assets was reduced to the minimum amounts allowed under the Settlement ($73 million in 1996 and $54 million in 1997). For each full year that the rate freeze remains in effect, CL&P agreed to amortize an additional $44 million of regulatory assets. On July 30, 1997, the DPUC issued a decision in its prudence review of nuclear cost recovery issues disallowing CL&P's recovery of all of the replacement power costs associated with the ongoing outages at Millstone. CL&P has expensed, and will continue to expense, replacement power costs for the Millstone outages as they are incurred. The DPUC is required to review a utility's rates every four years if there has not been a rate proceeding during such period. In 1997, the DPUC conducted such a review of CL&P's rates, including an analysis of the possibility of removing one or more of the Millstone nuclear units from CL&P's rate base. On December 31, 1997, the DPUC issued its ruling in this matter. The decision did not effect a change in CL&P's rates, but set forth findings and conclusions that could be used to do so in additional proceedings. The most significant conclusion was that Millstone 1 should be removed from CL&P's rate base, which would cause an annual revenue reduction of approximately $30.5 million. The decision stated that the DPUC would open an interim rate case immediately to remove Millstone 1 from CL&P's rates and simultaneously to remove an additional $110.5 million of other expenses from rates related to perceived overearnings. On February 25, 1998, the DPUC issued a decision reducing CL&P's rates by approximately 1.4 percent to reflect the removal of Millstone 1 from rates. This reduction reflects the removal from rates of O&M, depreciation and investment return related to Millstone 1, net of replacement power costs. In addition, the decision requires CL&P to accelerate the amortization of regulatory assets by $110.5 million, which includesing the $44 million from the 1996 Settlement. The interim rate reduction became effective on March 1, 1998. CL&P also was directed to file a full rate case on June 1, 1998, to address potential overearnings amounting to an additional $150 million in 1998. The effective date of any rate order will be September 28, 1998. In addition, the DPUC has scheduled hearings for April 1, 1998 to determine the status of Millstone 3 and Millstone 2. If the units are not operating by that date, the DPUC will consider their removal from rates. A similar restart status hearing is anticipated for June 1, 1998. The DPUC also will consider CL&P's analyses of the economic benefits of the continued operation of Millstone 1 and 2 in the context of CL&P's next integrated resource planning proceeding, which begins in April 1998. NUCLEAR DECOMMISSIONING CONNECTICUT YANKEE CL&P has a 34.5 percent ownership interest in the Connecticut Yankee nuclear generating facility (CY or the plant). On December 4, 1996, the Board of Directors of Connecticut Yankee Atomic Power Company voted unanimously to cease permanently the production of power at the plant. The decision to retire CY from commercial operation was based on an economic analysis of the costs of operating it compared to the costs of closing it and incurring replacement power costs over the remaining period of the plant's operating license, which would have expired in 2007. The economic analysis showed that closing the plant and incurring replacement power costs produced substantial savings. CY has undertaken a number of regulatory filings intended to implement the decommissioning. In late December 1996, CY filed an amendment to its power contracts with the FERC to clarify the obligations of its purchasing utilities following the decision to cease power production. At December 31, 1997, CL&P's share of these obligations was approximately $214 million, including the cost of decommissioning and the recovery of existing assets. Management expects that the company will continue to be allowed to recover such FERC approved costs from its customers. Accordingly, CL&P has recognized its share of the estimated costs as a regulatory asset, with a corresponding obligation, on its balance sheets. MAINE YANKEE CL&P has a 12 percent ownership interest in the Maine Yankee (MY) nuclear generating facility. On August 6, 1997, the Board of Directors of Maine Yankee Atomic Power Company (MYAPC) voted unanimously to retire MY. On January 14, 1998, FERC released a draft order on the MYAPC application to amend its power contracts with the owner/purchasers and revise its decommissioning and other charges. FERC has accepted the proposed application for filing and made the amendments and the proposed charges under the contracts effective on January 15, 1998, subject to refund after hearings. At December 31, 1997, CL&P's share of the estimated remaining obligation, including decommissioning, amounted to approximately $104 million. Under the terms of the contracts with MYAPC, the shareholders' sponsor companies, including CL&P, are responsible for their proportionate share of the costs of the unit, including decommissioning. Management expects that CL&P will be allowed to recover these costs from it's customers. Accordingly, CL&P has recognized these costs as a regulatory asset, with a corresponding obligation on its balance sheet. MILLSTONE AND SEABROOK CL&P's estimated cost to decommission its shares of the Millstone plants and Seabrook is approximately $1.1 billion in year end 1997 dollars. These costs are being recognized over the lives of the respective units with a portion currently being recovered through rates. As of December 31, 1997, CL&P's share of the market value of the contributions already made to the decommissioning trusts, including their investment returns, was approximately $369 million. See the "Notes to Consolidated Financial Statements," Note 4, for further information on nuclear decommissioning, including the CL&P's share of costs to decommission the other regional nuclear generating units. ENVIRONMENTAL MATTERS CL&P is potentially liable for environmental cleanup costs at a number of sites inside and outside its service territory. To date, the future estimated environmental remediation liability has not been material with respect to the earnings or financial position of CL&P. At December 31, 1997, CL&P had recorded an environmental reserve of approximately $6.4 million. See the "Notes to Consolidated Financial Statements," Note 12C, for further information on environmental matters. YEAR 2000 ISSUE The Year 2000 issue exists because many computer systems and applications currently use two-digit date fields to designate a year. As the change of the century occurs, date-sensitive systems may recognize the year 2000 as 1900, or not recognize it at all. This inability to recognize or properly treat the year 2000 may cause NU's systems to process critical financial and operational information incorrectly. The NU system has assessed and continues to assess the impact of the Year 2000 issue on its operating and reporting systems. The assessment of the nuclear operating systems is continuing and is expected to be completed in the summer of 1998. The NU system will utilize both internal and external resources to reprogram or replace, and test the software for Year 2000 modifications. The total estimated remaining cost of the Year 2000 project for the NU system is $37 million and is being funded through operating cash flows. This estimate does not include any costs for the replacement or repair of equipment or devices that may be identified during the assessment process. The majority of these costs will be expensed as incurred over the next two years. To date, the NU system has incurred and expensed approximately $4 million related to the assessment of and preliminary efforts in connection with its Year 2000 project. The costs of the project and the date on which the NU system plans to complete the Year 2000 modifications are based on management's best estimates, which were derived utilizing numerous assumptions of future events, including the continued availability of certain resources, third-party modification plans and other factors. However, there can be no guarantee that these estimates will be achieved, and actual results could differ materially from those plans. If the NU system's remediation plan is not successful, there could be a significant disruption of the company's operations. RISK-MANAGEMENT INSTRUMENTS The following discussion about the company's risk-management activities includes forward-looking statements that involve risk and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. This analysis presents the hypothetical loss in earnings related to the fuel price and interest rate market risks not covered by the risk- management instruments at December 31, 1997. The company uses swaps, collars, puts, and calls to manage the market risk exposures associated with changes in fuel prices and variable interest rates. The company does not use these risk-management instruments for speculative purposes. For more information on CL&P's use of risk management instruments, see the "Notes to Consolidated Financial Statements," Note 13. In the generation of electricity, the most significant variable cost component is the cost of fuel. Typically, most of CL&P's fuel purchases are protected by a regulatory fuel price adjustment clause. However, for a specific, well-defined volume of fuel that is excluded from the fuel price adjustment clause (unprotected volume), CL&P employs fuel price risk-management instruments to protect itself against the risk of rising fuel prices, thereby limiting fuel costs and protecting its profit margins. These risks are created by the sale of long-term, fixed-price electricity contracts to wholesale customers and the purchase or generation of replacement power related to the ongoing Millstone nuclear outages. At December 31, 1997, CL&P had outstanding agreements with a total notional value of approximately $327 million. The settlement amounts associated with the instruments reduced fuel expense by approximately $7.8 million. CL&P has had experience using various fuel price risk-management instruments since 1994, most of which have been in the form of fuel price swaps. At December 31, 1997 approximately 30 percent of the unprotected volume was covered by fuel price risk-management instrument (hedge ratio) for 1997. This effectively fixed or bounded the fuel cost and thus eliminated the market price risk for this covered volume of fuel. At December 31, 1997, the company had a hedge ratio of 44 percent for 1998. At December 31, 1997, the 56 percent uncovered volume of fuel for 1998, as a result of not being hedged, is subject to changes in actual market prices. Therefore, assuming a hypothetical 10 percent increase in the average 1997 price of fuel in 1998, the result would be a negative pre-tax impact on earnings of approximately $12.4 million. This analysis is based on the broad assumption that the entire uncovered volume of fuel remains constant and will be purchased the spot market. This assumption is subject to change as the uncovered volume of fuel likely will change during the next year. Other assumptions used in this analysis, projections of the fuel mix, the amount of long-term sales contracts or the projected Millstone restart dates, also are subject to change. RESULTS OF OPERATIONS Income Statement Variances (Millions of Dollars) 1997 over/(under) 1996 1996 over/(under) 1995 Amount Percent Amount Percent Operating revenues $ 68 3% $ 10 - % Fuel, purchased and net interchange power 146 18 222 37 Other operation (1) - 113 18 Maintenance 56 19 107 56 Amortization of regulatory assets, net 4 7 3 6 Federal and state income taxes (68) (a) (181) (100) Other income, net (23) (a) 6 42 Net income (89) (a) (256) (a) (a) Percentage greater than 100 OPERATING REVENUES Total operating revenues increased in 1997, primarily due to higher fuel recoveries and higher conservation recoveries. Fuel recoveries increased $33 million, primarily due to a higher fuel adjustment clause rate in 1997. Conservation recoveries increased by $17 million primarily due to a 1996 reserve for over-recoveries of demand-side-management costs. Retail kilowatt hour sales were essentially unchanged in 1997. Total operating revenues increased in 1996, primarily due to higher retail sales and regulatory decisions, partially offset by lower fuel recoveries and lower wholesale revenues. Retail sales increased 1.8 percent ($29 million) primarily due to modest economic growth in 1996. Regulatory decisions increased revenues by $15 million primarily due to the mid-1995 retail rate increase, partially offset by 1996 reserves for over-recoveries of demand-side management costs. Fuel recoveries decreased $24 million primarily due to lower average fossil fuel prices. Wholesale revenues decreased $18 million primarily due to higher recognition in 1995 of lump-sum payments for the termination of a long-term contract and capacity sales contracts that expired in 1995. FUEL, PURCHASED AND NET INTERCHANGE POWER Fuel, purchased and net interchange power expense increased in 1997, primarily due to replacement power costs associated with the Millstone outages and the expensing in 1997 of replacement power costs incurred in 1996. Fuel, purchased and net interchange power expense increased in 1996, primarily due to replacement power due to the nuclear outages and the 1996 write-off of the generation utilization adjustment clause (GUAC) balances under the Settlement, partially offset by lower nuclear generation and the timing of the recognition of costs under the company's fuel clauses. OTHER OPERATION AND MAINTENANCE Other operation and maintenance expenses increased in 1997, primarily due to higher costs associated with the Millstone restart effort ($173 million), higher charges from Maine Yankee ($9 million), partially offset by lower recognition of nuclear refueling outage costs primarily as a result of the 1996 Rate Settlement ($72 million), lower capacity charges from Connecticut Yankee as a result of a property tax refund ($27 million), lower administrative and general expenses ($23 million) primarily due to lower pensions and benefit costs and lower storm expenses. Other operation and maintenance expenses increased in 1996, primarily due to higher costs associated with the Millstone restart effort ($93 million) and higher 1996 costs to ensure adequate generating capacity ($39 million). In addition, 1996 costs reflect higher storm and reliability expenditures, higher recognition of conservation expenses and higher marketing costs. AMORTIZATION OF REGULATORY ASSETS, NET Amortization of regulatory assets, net increased in 1997, primarily due to the completion of cogeneration deferrals in 1996 and increased amortization in 1997, partially offset by the completion of CL&P's Seabrook amortization in 1996. Amortization of regulatory assets, net increased in 1996, primarily due to lower cogeneration deferrals and the accelerated amortization of regulatory assets as a result of the Settlement, partially offset by the completion of the Millstone 3 phase-in amortization in 1995. FEDERAL AND STATE INCOME TAXES Federal and state income taxes decreased in 1997 and 1996, primarily due to lower book taxable income. OTHER INCOME, NET Other income, net decreased in 1997, primarily due to cost associated with the accounts receivable facility, nonutility marketing and advertising costs and lower miscellaneous income. Other income, net increased in 1996, primarily due to higher income on temporary cash investments in 1996. The Connecticut Light and Power Company and Subsidiaries SELECTED FINANCIAL DATA(a) 1997 1996 1995 1994 1993 (Restated) (Restated) (Thousands of Dollars) Operating Revenues....... $2,465,587 $2,397,460 $2,387,069 $2,328,052 $2,366,050 Operating (Loss)/ Income......... (7,619) 59,142 324,026 286,948 241,655 Net (Loss)/Income (139,597) (50,868) 205,216 198,288 191,449(b) Cash Dividends on Common Stock... 5,989 138,608 164,154 159,388 160,365 Total Assets..... 6,081,223 6,244,036 6,045,631 6,217,457 6,397,405 Long-Term Debt(c) 2,043,327 2,038,521 1,822,018 1,823,690 2,057,280 Preferred Stock Not Subject to Mandatory Redemption.... 116,200 116,200 116,200 166,200 166,200 Preferred Stock Subject to Mandatory Redemption(c). 155,000 155,000 155,000 230,000 230,000 Obligations Under Capital Leases(c) 158,118 155,708 172,264 175,969 177,418 SEGMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) (Restated) Quarter Ended(a) 1997 March 31 June 30 September 30 December 31 Operating Revenues $624,908 $574,841 $627,712 $638,126 Operating Income/(Loss) $ 9,943 $(19,659) $ 1,365 $ 732 Net Loss $(19,636) $(50,161) $(33,160) $(36,640) 1996 Operating Revenues $659,355 $542,999 $599,505 $595,601 Operating Income/(Loss) $ 77,641 $ 19,895 $ (3,051) $(35,343) Net Income/(Loss) $ 50,515 $ (6,002) $(30,582) $(64,799) (a) Reclassifications of prior data have been made to conform with the current presentation. (b) Includes the cumulative effect of change in accounting for municipal property tax expense, which increased earnings for common shares by $47.7 million. (c) Includes portion due within one year. The Connecticut Light and Power Company and Subsidiaries STATISTICS Gross Electric Average Utility Plant Annual December 31, Use Per Electric (Thousands of kWh Sales Residential Customers Employees Dollars) (Millions) Customer (kWh) (Average) (December 31) 1997 $6,639,786 26,766 8,526 1,103,309 2,163 1996 6,512,659 26,043 8,639 1,099,340 2,194 1995 6,389,190 26,366 8,506(a) 1,094,527 2,270 1994 6,327,967 26,975 8,775 1,086,400 2,587 1993 6,214,401 26,107 8,519 1,078,925 2,676 (a) Effective January 1, 1996, the amounts shown reflect billed and unbilled sales. 1995 has been restated to reflect this change. EX-13.3 4 ANNUAL REPORT OF WMECO EXHIBIT 13.3 WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY AMENDED 1997 ANNUAL REPORT Western Massachusetts Electric Company and Subsidiary Amended 1997 Annual Report Index Contents Page Consolidated Balance Sheets (Restated)............................... 2-3 Consolidated Statements of Income (Restated)......................... 4 Consolidated Statements of Cash Flows (Restated)..................... 5 Consolidated Statements of Common Stockholder's Equity (Restated).................................................... 6 Notes to Consolidated Financial Statements (Restated)................ 7 Report of Independent Public Accountants............................. 39 Management's Discussion and Analysis of Financial Condition and Results of Operations (Restated)..................... 40 Selected Financial Data (Restated)................................... 51 Statements of Quarterly Financial Data (Restated).................... 51 Statistics........................................................... 52 Preferred Stockholder and Bondholder Information.....................Back Cover PART I. FINANCIAL INFORMATION WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------------- At December 31, 1997 1996 (Restated) (Restated) - ---------------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS - ------ Utility Plant, at original cost: Electric................................................. $ 1,284,288 $ 1,257,097 Less: Accumulated provision for depreciation.......... 559,119 503,989 ------------- ------------ 725,169 753,108 Construction work in progress............................ 19,038 15,968 Nuclear fuel, net........................................ 30,907 30,296 ------------- ------------ Total net utility plant.............................. 775,114 799,372 ------------- ------------ Other Property and Investments: Nuclear decommissioning trusts, at market................ 102,708 83,611 Investments in regional nuclear generating companies, at equity.................................... 15,741 15,448 Other, at cost........................................... 4,900 4,367 ------------- ------------ 123,349 103,426 ------------- ------------ Current Assets: Cash..................................................... 105 67 Investments in securitizable assets...................... 25,280 - Receivables, less accumulated provision for uncollectible accounts of $50,000 in 1997 and of $2,121,000 in 1996.............................. 2,739 40,168 Accounts receivable from affiliated companies............ 3,933 3,525 Taxes receivable......................................... 10,768 1,778 Accrued utility revenues................................. - 12,394 Fuel, materials and supplies, at average cost............ 5,860 5,317 Prepayments and other.................................... 14,945 12,262 ------------- ------------ 63,630 75,511 ------------- ------------ Deferred Charges: Regulatory assets........................................ 211,377 210,852 Unamortized debt expense................................. 2,695 1,866 Other.................................................... 2,963 888 ------------- ------------ 217,035 213,606 ------------- ------------ Total Assets......................................... $ 1,179,128 $ 1,191,915 ============= ============
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS
- --------------------------------------------------------------------------------------- At December 31, 1997 1996 (Restated) (Restated) - --------------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock--$25 par value--authorized and outstanding 1,072,471 shares in 1997 and 1996.......... $ 26,812 $ 26,812 Capital surplus, paid in................................ 151,171 150,911 Retained earnings (Note 1).............................. 58,608 104,212 ------------- ------------ Total common stockholder's equity.............. 236,591 281,935 Cumulative preferred stock-- $100 par value-- authorized 1,000,000 shares; outstanding 200,000 shares in 1997 and 1996; $25 par value--authorized 3,600,000 shares; outstanding 840,000 shares in 1997 and 1996 Preferred stock not subject to mandatory redemption..... 20,000 20,000 Preferred stock subject to mandatory redemption......... 19,500 21,000 Long-term debt.......................................... 386,849 334,742 ------------- ------------ Total capitalization........................... 662,940 657,677 ------------- ------------ Obligations Under Capital Leases.......................... 217 29,269 ------------- ------------ Current Liabilities: Notes payable to banks.................................. 15,000 - Notes payable to affiliated company..................... 14,350 47,400 Long-term debt and preferred stock--current portion................................................ 11,300 14,700 Obligations under capital leases--current portion................................................ 32,670 2,965 Accounts payable........................................ 30,571 26,698 Accounts payable to affiliated companies................ 21,209 20,256 Accrued taxes........................................... 522 2,659 Accrued interest........................................ 3,318 5,643 Other................................................... 2,446 4,754 ------------- ------------ 131,386 125,075 ------------- ------------ Deferred Credits: Accumulated deferred income taxes....................... 246,453 249,886 Accumulated deferred investment tax credits............. 23,364 24,833 Deferred contractual obligations........................ 93,628 84,598 Other................................................... 21,140 20,577 ------------- ------------ 384,585 379,894 ------------- ------------ Commitments and Contingencies (Note 12) ------------- ------------ Total Capitalization and Liabilities........... $ 1,179,128 $ 1,191,915 ============= ============
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME
- --------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 (Restated) (Restated) 1995 - --------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues............................. $ 426,447 $ 421,337 $ 420,434 ---------- ---------- ---------- Operating Expenses: Operation -- Fuel, purchased and net interchange power. 140,976 115,691 86,738 Other..................................... 153,399 136,897 143,000 Maintenance.................................. 81,466 56,201 37,447 Depreciation................................. 39,753 39,710 37,924 Amortization of regulatory assets, net....... 6,428 9,170 19,562 Federal and state income taxes............... (15,142) 10,628 14,060 Taxes other than income taxes................ 19,316 19,850 18,639 ---------- ---------- ---------- Total operating expenses (Note 1)...... 426,196 388,147 357,370 ---------- ---------- ---------- Operating Income............................... 251 33,190 63,064 ---------- ---------- ---------- Other Income: Equity in earnings of regional nuclear generating companies....................... 1,524 1,800 1,771 Other, net................................... (1,106) 1,153 1,232 Income taxes................................. 1,026 1,068 262 ---------- ---------- ---------- Other income, net...................... 1,444 4,021 3,265 ---------- ---------- ---------- Income before interest charges......... 1,695 37,211 66,329 ---------- ---------- ---------- Interest Charges: Interest on long-term debt................... 26,046 24,094 26,840 Other interest............................... 3,109 2,028 356 ---------- ---------- ---------- Interest charges, net.................. 29,155 26,122 27,196 ---------- ---------- ---------- Net (Loss)/Income (Note 1)..................... $ (27,460) $ 11,089 $ 39,133 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) - -------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Activities: Net (Loss)/Income........................................... $ (27,460) $ 11,089 $ 39,133 Adjustments to reconcile to net cash from operating activities: Depreciation.............................................. 39,753 39,710 37,924 Deferred income taxes and investment tax credits, net..... (1,256) 1,195 3,418 Deferred Millstone 3 return............................... - - 7,146 Recoverable energy costs, net of amortization............. (8,184) (10,517) 1,285 Amortization of nuclear refueling outage, net of deferrals 8,819 6,188 (8,857) Other sources of cash..................................... 27,804 21,248 32,266 Other uses of cash........................................ (21,215) (10,271) (8,039) Changes in working capital: Receivables and accrued utility revenues ................ 29,415 (1,853) (1,933) Fuel, materials and supplies.............................. (543) (203) (285) Accounts payable.......................................... 4,826 20,875 (11,669) Sale of receivables and accrued utility revenues.......... 20,000 - - Investment in securitizable assets........................ (25,280) - - Accrued taxes............................................. (2,137) (805) (3,474) Other working capital (excludes cash)..................... (16,882) (8,144) 1,256 ----------- ----------- ----------- Net cash flows from operating activities (Note 1)............. 27,660 68,512 88,171 ----------- ----------- ----------- Financing Activities: Issuance of long-term debt.................................. 60,000 - - Net (decrease)/increase in short-term debt.................. (18,050) 23,350 24,050 Reacquisitions and retirements of long-term debt............ (14,700) - (34,550) Reacquisitions and retirements of preferred stock........... - (36,500) (15,675) Cash dividends on preferred stock........................... (3,140) (5,305) (4,944) Cash dividends on common stock.............................. (15,004) (16,494) (30,223) ----------- ----------- ----------- Net cash flows from/(used for) financing activities........... 9,106 (34,949) (61,342) ----------- ----------- ----------- Investment Activities: Investment in plant: Electric utility plant.................................... (26,249) (23,468) (27,084) Nuclear fuel.............................................. (8) 541 75 ----------- ----------- ----------- Net cash flows used for investments in plant................ (26,257) (22,927) (27,009) NU System Money Pool........................................ - - 8,750 Investment in nuclear decommissioning trusts................ (9,645) (9,794) (8,503) Other investment activities, net............................ (826) (977) 46 ----------- ----------- ----------- Net cash flows used for investments........................... (36,728) (33,698) (26,716) ----------- ----------- ----------- Net Increase/(Decrease) In Cash For The Period................ 38 (135) 113 Cash - beginning of period.................................... 67 202 89 ----------- ----------- ----------- Cash - end of period.......................................... $ 105 $ 67 $ 202 =========== =========== =========== Supplemental Cash Flow Information: Cash paid/(refunded) during the year for: Interest, net of amounts capitalized........................ $ 28,711 $ 21,725 $ 25,551 =========== =========== =========== Income taxes................................................ $ (1,121) $ 7,816 $ 14,385 =========== =========== =========== Increase in obligations: Niantic Bay Fuel Trust...................................... $ 660 $ 669 $ 7,851 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- --------------------------------------------------------------------------------------- Capital Retained Common Surplus, Earnings(a) Stock Paid In (Note 1) Total - --------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1995............... $26,812 $149,683 $111,586 $288,081 Net income for 1995.................. 39,133 39,133 Cash dividends on preferred stock.............................. (4,944) (4,944) Cash dividends on common stock....... (30,223) (30,223) Loss on the retirement of preferred stock.............................. (256) (256) Capital stock expenses, net.......... 499 499 -------- --------- --------- --------- Balance at December 31, 1995............. 26,812 150,182 115,296 292,290 Net income for 1996 (Note 1)......... 11,089 11,089 Cash dividends on preferred stock.............................. (5,305) (5,305) Cash dividends on common stock....... (16,494) (16,494) Loss on the retirement of preferred stock.............................. (374) (374) Capital stock expenses, net.......... 729 729 -------- --------- --------- --------- Balance at December 31, 1996 (Restated).. 26,812 150,911 104,212 281,935 Net loss for 1997 (Note 1)........... (27,460) (27,460) Cash dividends on preferred stock.............................. (3,140) (3,140) Cash dividends on common stock....... (15,004) (15,004) Capital stock expenses, net.......... 260 260 -------- --------- --------- --------- Balance at December 31, 1997 (Restated).. $26,812 $151,171 $ 58,608 $236,591 ======== ========= ========= =========
(a) The company has dividend restrictions imposed by its long-term debt agreements. At December 31, 1997, these restrictions totaled approximately $21.5 million. The accompanying notes are an integral part of these financial statements. Western Massachusetts Electric Company and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SECURITIES AND EXCHANGE COMMISSION INQUIRY In a letter dated March 25, 1998, the Securities and Exchange Commission (SEC) inquired into Northeast Utilities'(NU) accounting for nuclear compliance costs. These costs are the unavoidable incremental costs associated with the current nuclear outages required to be incurred prior to restart of the units in accordance with correspondence received from the Nuclear Regulatory Commission (NRC) early in 1996. The SEC's view is that these unavoidable costs associated with nuclear outages and procedures to be implemented at nuclear power plants in response to regulatory requirements required prior to restart of the units should be expensed as incurred. During 1996 and 1997, NU and its wholly owned subsidiaries, The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO), reserved for these unavoidable incremental costs that they expected to incur to meet NRC standards. The SEC advised NU, CL&P, PSNH and WMECO to reflect these costs as they are incurred. While NU and its independent auditors, Arthur Andersen LLP, believed the accounting was required by, and was in accordance with, generally accepted accounting principles, NU has agreed to adjust its accounting for nuclear compliance costs and amend its 1996 and 1997 Form 10-K filings. The financial statements in this report have been restated to reflect the change in accounting. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. ABOUT WESTERN MASSACHUSETTS ELECTRIC COMPANY Western Massachusetts Electric Company and Subsidiary (WMECO or the company), CL&P, Holyoke Water Power Company (HWP), PSNH and North Atlantic Energy Corporation (NAEC) are the operating subsidiaries comprising the Northeast Utilities system (the NU system) and are wholly owned by NU. The NU system furnishes franchised retail electric service in Connecticut, New Hampshire and western Massachusetts through CL&P, PSNH, WMECO and HWP. The fifth wholly owned subsidiary, NAEC, sells all of its entitlement to the capacity and output of the Seabrook nuclear power plant (Seabrook) to PSNH. In addition to its franchised retail service, the NU system furnishes firm and other wholesale electric services to various municipalities and other utilities, and participates in limited retail access programs, providing off-system retail electric service. The NU system serves about 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues. Other wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing and other services to the NU system companies. Northeast Nuclear Energy Company (NNECO) acts as agent for the NU system companies and other New England utilities in operating the Millstone nuclear generating facilities. In addition, CL&P and WMECO each have established a special purpose subsidiary whose business consists of the purchase and resale of receivables. For information regarding WMECO's subsidiary, see Note 11, "Sale of Customer Receivables and Accrued Utility Revenues." B. PRESENTATION The consolidated financial statements of WMECO include the accounts of its wholly owned subsidiary. Significant intercompany transactions have been eliminated in consolidation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity and are subject to approval by various federal and state regulatory agencies. C. PUBLIC UTILITY REGULATION NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act). NU and its subsidiaries, including WMECO, are subject to the provisions of the 1935 Act. Arrangements among the NU system companies, outside agencies and other utilities covering inter- connections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. WMECO is subject to further regulation for rates, accounting, and other matters by the FERC and/or the applicable state regulatory commissions. For information regarding proposed changes in the nature of industry regulation, see Note 12A, "Commitments and Contingencies - Restructuring and Rate Matters." D. NEW ACCOUNTING STANDARDS The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 129, "Disclosure of Information about Capital Structure." SFAS 129 establishes standards for disclosing information about an entity's capital structure. WMECO's current disclosures are consistent with the requirements of SFAS 129. During June 1997, the FASB issued SFAS 130, "Reporting Comprehensive Income" and SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." SFAS 130 establishes standards for the reporting and disclosure of comprehensive income. To date, WMECO has not had material transactions that would be required to be reported as comprehensive income. SFAS 131 determines the standards for reporting and disclosing qualitative and quantitative information about a company's operating segments. This information includes segment profit or loss, certain segment revenue and expense items and segment assets and a reconciliation of these segment disclosures to corresponding amounts in the company's general purpose financial statements. WMECO currently evaluates management performance using a cost-based budget, and the information required by SFAS 131 is not available. Therefore, these disclosure requirements are not applicable. Management believes that the implementation of SFAS 130 and SFAS 131 will not have a material impact on WMECO's current disclosures. See Note 11, "Sale of Customer Receivables and Accrued Utility Revenues," and Note 12C, "Commitments and Contingencies -- Environmental Matters," for information on other newly issued accounting and reporting standards related to those specific areas. E. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT Regional Nuclear Generating Companies: WMECO owns common stock of four regional nuclear generating companies (Yankee companies). WMECO's investments in the Yankee companies are accounted for on the equity basis due to WMECO's ability to exercise significant influence over their operating and financial policies. The Yankee companies, with WMECO's ownership interests, are: Connecticut Yankee Atomic Power Company (CYAPC) ............... 9.5% Yankee Atomic Electric Company (YAEC) ......................... 7.0 Maine Yankee Atomic Power Company (MYAPC) ..................... 3.0 Vermont Yankee Nuclear Power Corporation (VYNPC) .............. 2.5 WMECO's investments in the Yankee companies at December 31, 1997 are: (Thousands of Dollars) CYAPC .............................................. $10,552 YAEC ............................................... 1,465 MYAPC .............................................. 2,370 VYNPC .............................................. 1,354 ------- $15,741 ------- Each Yankee company owns a single nuclear generating unit. Under the terms of the contracts with the Yankee companies, the shareholders- sponsors are responsible for their proportionate share of the costs of each unit, including decommissioning. The energy and capacity costs from VYNPC and nuclear decommissioning costs of the Yankee companies that have been shut down are billed as purchased power to WMECO. The electricity produced by the Vermont Yankee nuclear generating facility (VY) is committed substantially on the basis of ownership interests and is billed pursuant to contractual agreements. YAEC's, CYAPC's and MYAPC's nuclear power plants were shut down permanently on February 26, 1992, December 4, 1996, and August 6, 1997, respectively. Under ownership agreements with the Yankee companies, WMECO may be asked to provide direct or indirect financial support for one or more of the companies. For more information on the Yankee companies, see Note 3, "Nuclear Decommissioning," and Note 12F, "Commitments and Contingencies --Long-Term Contractual Arrangements." Millstone 1: WMECO has a 19 percent joint-ownership interest in Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approximately $91 million and $90.2 million, respectively, and the accumulated provision for depreciation included approximately $40.1 million and $37.2 million, respectively, for WMECO's share of Millstone 1. WMECO's share of Millstone 1 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. Millstone 2: WMECO has a 19 percent joint-ownership interest in Millstone 2, a 870-MW nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approximately $162.4 million and $161.4 million, respectively, and the accumulated provision for depreciation included approximately $57.6 million and $51.7 million, respectively, for WMECO's share of Millstone 2. WMECO's share of Millstone 2 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. Millstone 3: WMECO has a 12.24 percent joint-ownership interest in Millstone 3, a 1,154-MW nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approximately $378.7 million and $377.7 million, respectively, and the accumulated provision for depreciation included approximately $110.1 million and $99.8 million, respectively, for WMECO's share of Millstone 3. WMECO's share of Millstone 3 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. The three Millstone units are out of service. NU hopes to return Millstone 3 to service in the early spring of 1998 and Millstone 2 three to four months after Millstone 3. Millstone 1 has been placed in extended maintenance status. Management is reviewing its options with respect to Millstone 1, including restart, early retirement and other options. In a draft ruling issued in February 1998, the Connecticut Department of Public Utility Control (DPUC) determined that Millstone 1 was no longer "used and useful" and ordered it removed from rate base. For more information regarding the Millstone units, see Note 3, "Nuclear Decommissioning," and Note 12B, "Commitments and Contingencies - Nuclear Performance." F. DEPRECIATION The provision for depreciation is calculated using the straight-line method based on estimated remaining lives of depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency. Except for major facilities, depreciation rates are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.2 percent in 1997 and 1996 and 3.1 percent in 1995. See Note 3, "Nuclear Decommissioning," for information on nuclear plant decommissioning. WMECO's nonnuclear generating facilities have limited service lives. Plant may be retired in place or dismantled based upon expected future needs, the economics of the closure and environmental concerns. The costs of closure and removal are incremental costs and, for financial reporting purposes, are accrued over the life of the asset as part of depreciation. At December 31, 1997 and 1996, the accumulated provision for depreciation included approximately $3.2 million, respectively, accrued for the cost of removal, net of salvage for nonnuclear generation property. G. REVENUES Other than revenues under fixed-rate agreements negotiated with certain wholesale, commercial and industrial customers, utility revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission. Regulatory commissions also have authority over the terms and conditions of nontraditional rate-making arrangements. At the end of each accounting period, WMECO accrues an estimate for the amount of energy delivered but unbilled. H. REGULATORY ACCOUNTING AND ASSETS The accounting policies of WMECO and the accompanying consolidated financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the rate-making process in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered through future revenues. Through their actions, regulators also may reduce or eliminate the value of an asset, or create a liability. If any portion of WMECO's operations were no longer subject to the provisions of SFAS 71, as a result of a change in the cost-of-service based regulatory structure or the effects of competition, WMECO would be required to write off related regulatory assets and liabilities unless there is a formal transition plan which provides for the recovery, through established rates, for the collection of approved stranded costs and to maintain the cost-of-service basis for the remaining regulated operations. At the time of transition, WMECO would be required to determine any impairment to the carrying costs of deregulated plant and inventory assets. The staff of the SEC has had concerns regarding the appropriateness of the utilities' ability to continue application of SFAS 71 for the generation portion of their business in a restructured environment. The SEC referred the issue to the Emerging Issues Task Force (EITF) of the FASB which reached a consensus and issued "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101," (EITF 97-4). The EITF concluded: (1) the future recognition of regulatory assets for the portion of the business that no longer qualifies for application of SFAS 71 depends on the regulators' treatment of the recovery of those costs and other stranded assets from cash flows of other portions of the business still considered to be regulated, and (2) a utility should discontinue the application of SFAS 71 when a legislative and regulatory plan has been enacted, which would include transition plans into a competitive environment, and when the stranded costs which are subject to future rate recovery are determined. EITF 97-4 became effective in August 1997. Electric utility industry restructuring within the state of Massachusetts will be effective March 1, 1998. WMECO has submitted its proposed restructuring plan to the Massachusetts Department of Telecommunications and Energy (DTE), formerly the Massachusetts Department of Public Utilities. If the DTE approves the plan in its current form, WMECO would discontinue the application of SFAS 71. However, the restructuring legislation enacted by the state of Massachusetts specifically provides for future deferrals and the cost recovery of generation-related assets as contemplated under the plan. As such, WMECO is not expected to have to write off either its generation-related assets or related regulatory assets. WMECO's generation-related regulatory assets were valued at approximately $188 million at December 31, 1997. The majority of WMECO's regulatory assets are related to its generation business. For more information on the WMECO's regulatory environment and the impacts of restructuring, see Note 12A, "Commitments and Contingencies- Restructuring and Rate Matters," and Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires the evaluation of long- lived assets, including regulatory assets, for impairment when certain events occur or when conditions exist that indicate the carrying amounts of assets may not be recoverable. SFAS 121 requires that any long-lived assets which are no longer probable of recovery through future revenues be revalued based on estimated future cash flows. If this revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. Management continues to believe it is probable that WMECO will recover its investments in long-lived assets through future revenues. This conclusion may change in the future as the implementation of restructuring plans within Massachusetts will generally require the formation of a separate generation entity that will be subject to competitive market conditions. As a result, WMECO will be required to assess the carrying amounts of its long-lived assets in accordance with SFAS 121. The components of WMECO's regulatory assets are as follows: At December 31, 1997 1996 (Thousands of Dollars) Income taxes, net (Note 2I) ..................... $ 63,716 $ 71,519 Unrecovered contractual obligations (Note 3) ...................................... 93,628 84,598 Recoverable energy costs (Note 2J) .............. 26,270 17,510 Other ........................................... 27,763 37,225 $211,377 $210,852 I. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the ratemaking treatment of the applicable regulatory commissions. See Note 8, "Income Tax Expense" for the components of income tax expense. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, which give rise to the accumulated deferred tax obligation is as follows: At December 31, 1997 1996 (Restated)(Restated) (Thousands of Dollars) Accelerated depreciation and other plant-related differences ................. $223,038 $218,389 Regulatory assets - income tax gross up ......... 30,175 29,457 Other ........................................... (6,760) 2,040 $246,453 $249,886 J. RECOVERABLE ENERGY COSTS Under the Energy Policy Act of 1992 (Energy Act), WMECO is assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (D&D assessment). The Energy Act requires that regulators treat D&D assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates, like any other fuel cost. WMECO is currently recovering these costs through rates. As of December 31, 1997, WMECO's total D&D deferrals were approximately $11.3 million. WMECO has a fuel adjustment clause (FAC) which includes energy costs along with capacity and transmission charges and credits that result from short-term transactions with other utilities and from certain FERC- approved contracts among the NU system's operating companies. The Massachusetts restructuring legislation will effectively eliminate the FAC, effective March 1, 1998. On August 20, 1997, WMECO filed with the DTE a joint motion for approval of a settlement agreement with the Massachusetts Attorney General which allowed WMECO to recover approximately $15.3 million of fuel costs for the period September 1997 through February 1998. Under the current FAC rate, WMECO continues to defer significant costs for future recovery. At December 31, 1997, WMECO's net recoverable energy costs were approximately $26.3 million, which includes approximately $11.3 million of costs related to WMECO's share of the D&D assessment. For additional information regarding recoverable energy costs see the MD&A. K. SPENT NUCLEAR FUEL DISPOSAL COSTS Under the Nuclear Waste Policy Act of 1982, WMECO must pay the United States Department of Energy (DOE) for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. Fees for nuclear fuel burned on or after April 7, 1983, are billed currently to customers and paid to the DOE on a quarterly basis. For nuclear fuel used to generate electricity prior to April 7, 1983 (prior-period fuel), payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the three-month Treasury Bill Yield Rate. At December 31, 1997, fees due to the DOE for the disposal of prior-period fuel were approximately $39.0 million, including interest costs of $23.4 million. The DOE was originally scheduled to begin accepting delivery of spent fuel in 1998. However, delays in identifying a permanent storage site have continually postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. The company has primary responsibility for the interim storage of its spent nuclear fuel. Current capability to store spent fuel at Millstone 1 and 2 are estimated to be adequate until 2004. Storage facilities for Millstone 3 are expected to be adequate for the projected life of the unit. Meeting spent fuel storage requirements beyond these periods could require new and separate storage facilities, the costs for which have not been determined. In November 1997, the U.S. District Court of Appeals for the D.C. Circuit ruled that the lack of an interim storage facility does not excuse the DOE from meeting its contractual obligation to begin accepting spent nuclear fuel no later than January 31, 1998. Currently, the DOE has not taken the spent nuclear fuel as scheduled and, as a result, may have to pay contract damages. The ultimate outcome of this legal proceeding is uncertain at this time. 3. NUCLEAR DECOMMISSIONING Millstone: WMECO's nuclear power plants have service lives that are expected to end during the years 2010 through 2025. Upon retirement, these units must be decommissioned. Current decommissioning studies concluded that complete and immediate dismantlement at retirement continues to be the most viable and economic method of decommissioning the three Millstone units. Decommissioning studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology and inflation. The estimated cost of decommissioning WMECO's ownership share of Millstone 1, 2 and 3, in year-end 1997 dollars, is $91.7 million, $82.1 million and $67.8 million, respectively. The Millstone units decommissioning costs will be increased annually by their respective escalation rates. Nuclear decommissioning costs are accrued over the expected service life of the units and are included in depreciation expense on the Consolidated Statements of Income. Nuclear decommissioning costs amounted to $6.2 million in 1997 and 1996 and $5.0 million in 1995. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Consolidated Balance Sheets. At December 31, 1997 and 1996, the balance in the accumulated reserve for depreciation amounted to $102.7 million and $83.6 million, respectively. WMECO has established external decommissioning trusts through a trustee for its portion of the costs of decommissioning Millstone 1, 2 and 3. Funding of the estimated decommissioning costs assumes levelized collections for the Millstone units and after-tax earnings on the Millstone decommissioning funds of approximately 5.5 percent. As of December 31, 1997, WMECO has collected, through rates, $59.7 million toward the future decommissioning costs of its share of the Millstone units, all of which has been transferred to external decommissioning trusts. Earnings on the decommissioning trusts increase the decommissioning trust balance and the accumulated reserve for depreciation. Unrealized gains and losses associated with the decommissioning trusts also impact the balance of the trust and the accumulated reserve for depreciation. Changes in requirements or technology, the timing of funding or dismantling, or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. WMECO attempts to recover sufficient amounts through its allowed rates to cover its expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by regulatory agencies is reflected in rates of WMECO. Based on present estimates and assuming its nuclear units operate to the end of their respective license periods, WMECO expects that the decommissioning trusts will be substantially funded when the units are retired from service. Millstone 1 has been placed in extended maintenance status while management is reviewing its options with respect to the unit. These include restart, early retirement and other options. Relating to management's consideration of the option to immediately retire Millstone 1 are certain Connecticut state law issues which relate to WMECO as minority owner. In its four-year rate review proceeding, the DPUC noted that CL&P may not be able to obtain its remaining investment in Millstone 1 if it were to determine that the unit had been prematurely shut down due to management imprudence. Additionally, there is a Connecticut statute which may limit CL&P's ability to collect future decommissioning charges related to Millstone 1 if Millstone 1 were to be terminated before the end of its expected life. At December 31, 1997, WMECO's net unrecovered Millstone 1 plant costs were $50.9 million and the remaining unrecovered decommissioning costs were approximately $44 million. Yankee Companies: VYNPC owns and operates a nuclear generating unit with a service life that is expected to end in 2012. WMECO's ownership share of estimated costs, in year-end 1997 dollars, of decommissioning this unit is $12.6 million. On August 6, 1997, the board of directors of MYAPC voted unanimously to cease permanently the production of power at its nuclear generating facility (MY). The NU system companies had relied on MY for approximately one percent of their capacity. During November 1997, MYAPC filed an amendment to its power contracts clarifying the obligations of its purchasing utilities following the decision to cease power production. During January 1998, the FERC accepted the amendments and proposed rates, subject to refund. At December 31, 1997, the remaining estimated obligation, including decommissioning, amounted to approximately $867.2 million, of which WMECO's share was approximately $26.0 million. On December 4, 1996, the board of directors of CYAPC voted unanimously to cease permanently the production of power at its nuclear generating plant (CY). During 1996, the NU system companies had relied on CY for approximately three percent of their capacity. During late December 1996, CYAPC filed an amendment to its power contracts clarifying the obligations of its purchasing utilities following the decision to cease power production. On February 27, 1997, the FERC approved an order for hearing which, among other things, accepted CYAPC's contract amendment. The new rates became effective March 1, 1997, subject to refund. At December 31, 1997, the remaining estimated obligation, including decommissioning, amounted to $619.9 million, of which WMECO's share was approximately $58.9 million. YAEC is in the process of decommissioning its nuclear facility. At December 31, 1997, the estimated remaining costs, including decommissioning, amounted to $124.4 million, of which WMECO's share was approximately $8.7 million. Under the terms of the contracts with MYAPC, CYAPC and YAEC, the shareholder-sponsor companies, including WMECO, are responsible for their proportionate share of the costs of the units, including decommissioning. Management expects that WMECO will continue to be allowed to recover these costs from its customers. Accordingly, WMECO has recognized these costs as regulatory assets, with corresponding obligations. Proposed Accounting: The staff of the SEC has questioned certain current accounting practices of the electric utility industry, including WMECO, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating units in the financial statements. In response to these questions, the FASB has agreed to review the accounting for closure and removal costs, including decommissioning. If current electric utility industry accounting practices for nuclear power plant decommissioning are changed, the annual provision for decommissioning could increase relative to 1997, and the estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation), with recognition of an increase in the cost of the related nuclear power plant. Management believes that WMECO will continue to be allowed to recover decommissioning costs through rates. 4. SHORT-TERM DEBT Limits: The amount of short-term debt borrowings that may be incurred by WMECO is subject to periodic approval by either the SEC under the 1935 Act or by the DTE. SEC authorization allowed WMECO, as of January 1, 1998, to incur short-term borrowings up to a maximum of $150 million. In addition, the charter of WMECO contains a provision which restricts the total amount of unsecured debt that it may borrow at any one time. As of January 1, 1998, this charter provision allowed WMECO to incur unsecured borrowings, whether short-term or long-term, up to a maximum of approximately $114 million. Credit Agreements: In May 1997, because of the potential for NU and CL&P to violate their various financial ratio tests, NU amended the three-year revolving credit agreement (Credit Agreement) with a group of 12 banks. Under the amended Credit Agreement, CL&P and WMECO are able to borrow, subject to the availability of first mortgage bond collateral, up to $313.75 million and $150 million, respectively. At December 31, 1997, CL&P and WMECO have issued first mortgage bonds to enable borrowings under this facility up to a maximum of $225 million and $90 million, respectively. NU, which cannot issue first mortgage bonds, will be able to borrow up to $50 million if NU consolidated, CL&P and WMECO each meet certain interest coverage tests for two consecutive quarters. In addition, CL&P and WMECO each must meet certain minimum quarterly financial ratios to access the Credit Agreement. Both CL&P and WMECO satisfied these tests for the quarter ending December 31, 1997. The overall limit for all of the borrowing system companies under the entire Credit Agreement is $313.75 million. The companies are obligated to pay a facility fee of .50 percent per annum of each bank's total commitment under this Credit Agreement which will expire in November 1999. At December 31, 1997 and 1996, there were $50 million and $27.5 million, respectively, in borrowings under this Credit Agreement. Of these borrowings, $15 million were borrowed by WMECO in 1997 and none were borrowed by WMECO in 1996. In addition to the Credit Agreement, NU, CL&P, WMECO, HWP and The Rocky River Realty Company (RRR) have various revolving credit lines through separate bilateral credit agreements. Under this facility, four banks maintain commitments to the respective companies totaling $56.25 million. NU, CL&P and WMECO may borrow up to the aggregate $56.25 million, whereas HWP and RRR may borrow up to their SEC or board authorized short-term debt limit of $5 million and $22 million, respectively. Under the terms of this facility, the companies are obligated to pay a facility fee of .15 percent per annum of each bank's total commitment. These commitments will expire in December 1998. At December 31, 1997 and 1996, there were no borrowings and $11.3 million in borrowings, respectively, under this facility. Under the credit facilities discussed above, WMECO may borrow funds on a short-term revolving basis under its respective agreements, using either fixed-rate loans or standby loans. Fixed rates are set using competitive bidding. Standby loans are based upon several alternative variable rates. The weighted average annual interest rate on WMECO's notes payable to banks outstanding on December 31, 1997 was 6.95 percent. WMECO had no borrowings under these facilities at December 31, 1996. Money Pool: Certain subsidiaries of NU, including WMECO, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the system, and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate. However, borrowings based on loans from NU parent bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 1997 and 1996, WMECO had $14.4 million and $47.4 million, respectively, of borrowings outstanding from the Pool. The interest rate on borrowings from the Pool at December 31, 1997 and 1996 was 5.8 percent and 6.3 percent, respectively. Maturities of short-term debt obligations were for periods of three months or less. For further information on short-term debt, including the ability to access these agreements, see the MD&A. 5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION Details of preferred stock not subject to mandatory redemptions are: December 31 Shares 1997 Outstanding Redemption December 31, December 31, Description Price 1997 1997 1996 1995 (Thousands of Dollars) 7.72% Series B of 1971 ........... $103.51 200,000 $20,000 $20,000 $20,000 1988 Adjustable Rate DARTS ........ - - - - 33,500 Total preferred stock not subject to mandatory redemption ........ $20,000 $20,000 $53,500 All or any part of each outstanding series of preferred stock may be redeemed by the company at any time at established redemption prices plus accrued dividends to the date of redemption. 6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock subject to mandatory redemption are: December 31 Shares 1997 Outstanding Redemption December 31, December 31, Description Price* 1997 1997 1996 1995 (Thousands of Dollars) 7.60% Series of 1987 ........... $25.64 840,000 $21,000 $21,000 $24,000 Less preferred stock to be redeemed within one year, net of reacquired stock .............. 60,000 1,500 - 1,500 Total preferred stock subject to mandatory redemption ......... $19,500 $21,000 $22,500 *Redemption price reduces in future years. The minimum sinking-fund provisions of the 1987 Series subject to mandatory redemption at December 31, 1997, for the years 1998 through 2002 is $1.5 million per year. In case of default on sinking-fund payments, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If the company is in arrears in the payment of dividends on any outstanding shares of preferred stock, the company would be prohibited from redemption or purchase of less than all of the preferred stock outstanding. All or part of the 7.60% Series of 1987 may be redeemed by the company at any time at an established redemption price plus accrued dividends to the date of redemption subject to certain refunding limitations. 7. LONG-TERM DEBT Details of long-term debt outstanding are: December 31, 1997 1996 (Thousands of Dollars) First Mortgage Bonds: 5 3/4% Series F, due 1997........... $ - $ 14,700 6 3/4% Series G, due 1998........... 9,800 9,800 6 1/4% Series X, due 1999........... 40,000 40,000 6 7/8% Series W, due 2000........... 60,000 60,000 7 3/8% Series B, due 2001........... 60,000 - 7 3/4% Series V, due 2002........... 85,000 85,000 7 3/4% Series Y, due 2024........... 50,000 50,000 Total First Mortgage Bonds..................... 304,800 259,500 Pollution Control Notes: Tax Exempt Variable Series A, due 2028........ 53,800 53,800 Fees and interest due for spent fuel disposal costs (Note 2K)................. 39,045 37,055 Less: Amounts due within one year............. 9,800 14,700 Unamortized premium and discount, net......... (996) (913) Long-term debt, net............................ $386,849 $334,742 Long-term debt maturities and cash sinking-fund requirements on debt outstanding at December 31, 1997 for the years 1998 through 2002 are approximately $9.8 million, $40 million, $60 million, $60 million and $85 million, respectively. In addition, there are annual one-percent sinking- and improvement-fund requirements, currently amounting to $1.5 million for 1998 and 1999 and $900 thousand for 2000 through 2002. Such sinking- and improvement-fund requirements may be satisfied by the deposit of cash or bonds by certification of property additions. All or any part of each outstanding series of first mortgage bonds may be redeemed by WMECO at any time at established redemption prices plus accrued interest to the date of redemption, except certain series which are subject to certain refunding limitations during their respective initial five-year redemption periods. Essentially all of WMECO's utility plant is subject to the lien of its first mortgage bond indenture. As of December 31, 1997 and 1996, WMECO has secured $53.8 million of pollution control notes with second mortgage liens on Millstone 1, junior to the liens of its first mortgage bond indenture. The average effective interest rate on the variable-rate pollution control notes was 3.5 percent for 1997 and 3.3 percent for 1996. 8. INCOME TAX EXPENSE The components of the federal and state income tax provisions (credited)/charged to operations are: For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) (Thousands of Dollars) Current income taxes: Federal............................ $(14,277) $ 7,007 $ 7,419 State.............................. (635) 1,358 2,961 Total current.................... (14,912) 8,365 10,380 Deferred income taxes, net: Federal............................ 3 2,054 4,130 State.............................. 210 609 1,003 Total deferred................... 213 2,663 5,133 Investment tax credits, net.......... (1,469) (1,468) (1,715) Total income tax (credit)/ expense............................ $(16,168) $ 9,560 $13,798 The components of total income tax expense are classified as follows: Income taxes charged to operating expenses................. $(15,142) $10,628 $14,060 Other income taxes .................. (1,026) (1,068) (262) Total income tax (credit)/ expense............................ $(16,168) $9,560 $13,798 Deferred income taxes are comprised of the tax effects of temporary differences as follows: For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) (Thousands of Dollars) Depreciation, leased nuclear fuel, settlement credits, and disposal costs............... $ 1,407 $ 32 $9,066 Energy adjustment clause........... 3,115 4,102 (1,549) Demand side management............. 321 1,557 (1,184) Nuclear plant deferrals............ (3,431) (2,258) 2,468 Pension............................ 999 (57) (482) Bond redemptions................... (535) (502) (572) Other............................. (1,663) (211) (2,614) Deferred income taxes, net........ $ 213 $ 2,663 $5,133 A reconciliation between income tax expense and the expected tax expense at the applicable statutory rate is as follows: For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) (Thousands of Dollars) Expected federal income tax at 35 percent of pretax income for........ $(15,270) $7,076 $18,526 Tax effect of differences: Depreciation........................... 1,352 2,280 2,173 Amortization of regulatory assets...... 1,916 1,029 1,665 Investment tax credit amortization..... (1,469) (1,468) (1,715) State income taxes, net of federal benefit...................... (225) 1,279 2,577 Adjustment for prior years' taxes...... (967) - (7,702) Dividends received reduction........... (408) (378) (481) Other, net............................. (1,097) (258) (1,245) Total income tax (credit)/expense........ $(16,168) $9,560 $13,798 9. LEASES WMECO and CL&P may finance up to $400 million of nuclear fuel for Millstone 1 and 2 and their respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement which is scheduled to expire July 31, 1998. The NBFT capital lease agreement, which was amended in February 1998, requires CL&P and WMECO to secure their obligation to repay the NBFT with up to $90 million of first mortgage bonds. CL&P and WMECO will issue these bonds by May 1998. WMECO and CL&P make quarterly lease payments for the cost of nuclear fuel consumed in the reactors based on a units-of-production method at rates which reflect estimated kilowatt hours of energy provided plus financing costs associated with the fuel in the reactors. Upon permanent discharge from the reactors, ownership of the nuclear fuel transfers to WMECO and CL&P. WMECO has also entered into lease agreements, some of which may be capital leases, for the use of data processing and office equipment, vehicles, nuclear control room simulators and office space. The provisions of these lease agreements generally provide for renewal options. The following rental payments have been charged to expense: Year Capital Leases Operating Leases 1997 .....................$ 1,820,000 $5,968,000 1996 .......................3,598,000 6,410,000 1995 ......................12,553,000 6,398,000 Interest included in capital lease rental payments was $1,820,000 in 1997, $1,858,000 in 1996, and $1,954,000 in 1995. Future minimum rental payments, excluding executory costs such as property taxes, state use taxes, insurance and maintenance, under long-term noncancelable leases, as of December 31, 1997, are: Year Capital Leases Operating Leases (Thousands of Dollars) 1998........................... $32,700 $ 3,700 1999........................... 36 3,400 2000........................... 36 3,100 2001........................... 36 2,800 2002........................... 36 2,500 After 2002..................... 70 18,600 Future minimum lease payments..................... 32,914 $34,100 Less amount representing interest..................... 14 Present value of future minimum lease payments............... $32,900 10. EMPLOYEE BENEFITS A. PENSION BENEFITS The NU system's subsidiaries participate in a uniform noncontributory defined benefit retirement plan covering all regular NU system employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. WMECO's direct portion of the NU system's pension credit, part of which was credited to utility plant, approximated $(5.7) million in 1997, $(2.0) million in 1996 and $(2.7) million in 1995. WMECO's pension (credits)/costs for 1997, 1996 and 1995 included approximately $(529) thousand, $1.0 million and $0.0 million, respectively, related to workforce reduction programs. Currently, WMECO funds annually an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code. Pension costs are determined using market-related values of pension assets. Pension assets are invested primarily in domestic and international equity securities and bonds. The components of net pension credit for WMECO are: For the Years Ended December 31, 1997 1996 1995 (Thousand of Dollars) Service cost....................... $ 1,346 $ 2,932 $ 1,645 Interest cost...................... 7,858 7,786 7,757 Return on plan assets.............. (31,874) (22,174) (29,798) Net amortization................... 16,944 9,458 17,669 Net pension (credit)............... $(5,726) $(1,998) $(2,727) For calculating pension cost, the following assumptions were used: For the Years Ended December 31, 1997 1996 1995 Discount rate...................... 7.75% 7.50% 8.25% Expected long-term rate of return......................... 9.25 8.75 8.50 Compensation/progression rate...... 4.75 4.75 5.00 The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: At December 31, 1997 1996 (Thousands of Dollars) Accumulated benefit obligation, including vested benefits at December 31, 1997 and 1996 of $(87,278,000) and $(85,094,000), respectively ...................... $( 93,555) $( 91,170) Projected benefit obligation......... $(109,536) $(107,816) Market value of plan assets.......... 181,028 157,863 Market value in excess of projected benefit obligation....... 71,492 50,047 Unrecognized transition amount....... (1,727) (1,963) Unrecognized prior service costs..... 1,142 1,213 Unrecognized net gain................ (62,370) (46,486) Prepaid pension asset ............... $ 8,537 $ 2,811 The following actuarial assumptions were used in calculating the plan's year-end funded status: At December 31, 1997 1996 Discount rate............................ 7.25% 7.75% Compensation/progression rate............ 4.25 4.75 B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS The NU system's subsidiaries provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (referred to as SFAS 106 benefits). These benefits are available for employees retiring from the company who have met specified service requirements. For current employees and certain retirees, the total SFAS 106 benefit is limited to two times the 1993 per-retiree health care cost. The SFAS 106 obligation has been calculated based on this assumption. WMECO's direct portion of SFAS 106 benefits, part of which were deferred or charged to utility plant, approximated $2.8 million in 1997, $3.8 million in 1996, and $4.4 million in 1995. WMECO is funding SFAS 106 postretirement costs through external trusts. WMECO is funding, on an annual basis, amounts that have been rate-recovered and which also are tax deductible under the Internal Revenue Code. The trust assets are invested primarily in equity securities and bonds. The components of health care and life insurance costs are: For the Years Ended December 31, 1997 1996 1995 (Thousands of Dollars) Service cost........................ $ 355 $ 490 $ 490 Interest cost....................... 2,011 2,236 2,544 Return on plan assets............... (2,088) (883) (718) Amortization of unrecognized transition obligation............. 1,641 1,641 1,641 Other amortization, net............. 868 353 473 Net health care and life insurance cost.................... $2,787 $3,837 $4,430 For calculating WMECO's SFAS 106 benefit costs, the following assumptions were used: For the Years Ended December 31, 1997 1996 1995 Discount rate....................... 7.75% 7.50% 8.00% Long-term rate of return - Health assets, net of tax......... 6.00 5.25 5.00 Life assets....................... 9.25 8.75 8.50 The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: At December 31, 1997 1996 (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees..................................... $(23,123) $(24,614) Fully eligible active employees.............. (84) (28) Active employees not eligible to retire...... (4,619) (5,449) Total accumulated postretirement benefit obligation.......................... (27,826) (30,091) Market value of plan assets................... 12,838 10,215 Accumulated postretirement benefit obligation in excess of plan assets......... (14,988) (19,876) Unrecognized transition amount................ 24,618 26,259 Unrecognized net gain......................... (9,630) (6,765) Accrued postretirement benefit liability...... $ - $ (382) The following actuarial assumptions were used in calculating the plan's year-end funded status: At December 31, 1997 1996 Discount rate................................. 7.25% 7.75% Health care cost trend rate (a)............... 5.76 7.23 (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 4.40 percent by 2001. The effect of increasing the assumed health care cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1997, by $1.7 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $131 thousand. The trust holding the health plan assets is subject to federal income taxes at a 39.6 percent tax rate. WMECO currently is recovering SFAS 106 costs through rates. 11. SALE OF CUSTOMER RECEIVABLES AND ACCRUED UTILITY REVENUES During 1996, WMECO entered into an agreement to sell up to $40 million of undivided ownership interests in eligible customer receivables and accrued utility revenues (receivables). The FASB issued SFAS 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," in June, 1996. SFAS 125 became effective on January 1, 1997, and establishes, in part, criteria for concluding whether a transfer of financial assets in exchange for consideration should be accounted for as a sale or as a secured borrowing. During May 1997, WMECO had restructured its sales agreement to comply with the conditions of SFAS 125 and account for transactions occurring under this program as a sale of assets. WMECO established a special purpose, wholly owned subsidiary whose business consists of the purchase and resale of receivables. For receivables sold, WMECO has retained collection responsibilities as agent for the purchaser under WMECO's agreement. As collections reduce previously sold receivables, new receivables may be sold. At December 31, 1997, approximately $20 million of receivables had been sold to a third-party purchaser by WMECO, through the use of its special purpose, wholly owned subsidiary, WMECO Receivables Corporation (WRC). All receivables transferred to WRC are assets owned by WRC and are not available to pay WMECO's creditors. For WRC's sales agreement with the third-party purchaser, the receivables were sold with limited recourse. WRC's sales agreement provides for a formula-based loss reserve in which additional receivables may be assigned to the third-party purchaser for costs such as bad debt. The third-party purchaser absorbs the excess amount in the event that actual loss experience exceeds the loss reserve. At December 31, 1997 approximately $3.0 million of assets had been designated as collateral by WRC. This amount represents the formula-based amount of credit exposure at December 31, 1997. Historical losses for bad debt for WMECO have been substantially less. During December 1997, Moody's Investors Service downgraded the rating on WMECO's first mortgage bonds. This downgrade brought WMECO's bond ratings to a level at which the sponsor of WMECO's accounts receivable program can take various actions, in its discretion, which would have the practical effect of limiting WMECO's ability to utilize the facility. To date, the sponsor has not notified WMECO that it will elect to exercise those rights, and the program is functioning in its normal mode. The WMECO accounts receivable program is terminable if WMECO's first mortgage bond credit ratings experience one more level of downgrade. CL&P's accounts receivable program could be terminated if its senior secured debt is downgraded two more steps from its current ratings. Concentrations of credit risk to the purchaser under WMECO's agreement with respect to the receivables are limited due to WMECO's diverse customer base within its service territory. For additional information on the accounts receivable program and WMECO's ability to utilize this program, see the MD&A. 12. COMMITMENTS AND CONTINGENCIES A. RESTRUCTURING AND RATE MATTERS During November 1997, the state of Massachusetts enacted a comprehensive electric utility industry restructuring bill (legislation). On December 31, 1997, WMECO filed its restructuring plan with the DTE, as required by the legislation. The WMECO restructuring plan describes the process by which WMECO will, beginning March 1, 1998, initiate a ten percent rate reduction for all customer rate classes and allow customers to choose their energy supplier. As part of the plan, the DTE authorized recovery of certain strandable above-market costs (strandable costs). The legislation gives the DTE the authority to determine the amount of strandable costs that will be eligible for recovery by utilities. Costs which will qualify as strandable costs and be eligible for recovery include, but are not limited to, certain above-market costs associated with generating facilities, costs associated with long-term commitments to purchase power at above-market prices from small power producers and nonutility generators, and regulatory assets and associated liabilities related to the generation portion of WMECO's business. Under the statute, if a distribution company claims that it is unable to meet a price reduction of ten percent initially and 15 percent by September 1, 1999, the distribution company may so state to the DTE and the DTE is provided with the authority to "explore all possible mechanisms and options within the limits of the constitution" to achieve the mandated rate reductions. The statute indicates that allowing a substitute company to provide standard offer service is one option that can be considered by the DTE. The costs of transitioning to competition will be mitigated through several steps, including divesting WMECO's non-nuclear generating assets at an auction to be held as soon as June 1998, and securitization of approximately $500 million in strandable costs by September 30, 1998. NU presently expects to participate, through a competitive affiliate, in the competitive bid process for WMECO's generation resources. Any net proceeds in excess of book value received from the divestiture of these units will be used to mitigate strandable costs. As required by the legislation, WMECO will continue to operate and maintain its transmission and local distribution network and deliver electricity to all customers. As noted above, the legislation has authorized Massachusetts utilities to finance a portion of the strandable costs through securitization, using rate reduction bonds. A separate transition charge will be collected over the life of the bonds to recover principal, interest and issuance costs. WMECO's ability to recover its strandable costs will depend on several factors, which include, but are not limited to, continuous recovery of the costs over the transitional period supported by the legislation, the aggregate amount of strandable costs which the company will be allowed to recover and the market price of electricity. Management believes that the company will recover its strandable costs. However, a change in one or more of these factors could affect the recovery of strandable costs and may result in a loss to the company. FERC Rate Proceedings: For information regarding the FERC rate proceedings for CYAPC and MYAPC, see Note 3, "Nuclear Decommissioning." B. NUCLEAR PERFORMANCE Millstone: The three Millstone units are managed by NNECO. Millstone 1, 2 and 3 have been out of service since November 4, 1995, February 21, 1996, and March 30, 1996, respectively, and are on the Nuclear Regulatory Commission's (NRC) watch list. NU has restructured its nuclear organization and is currently implementing comprehensive plans to restart the units. Subsequent to its January 31, 1996 announcement that Millstone had been placed on its watch list, the NRC stated that the units cannot return to service until independent, third-party verification teams have reviewed the actions taken to improve the design, configuration and employee concerns issues that prompted the NRC to place the units on its watch list. The actual date of the return to service for each of the units is dependent upon the completion of independent inspections and reviews by the NRC and a vote by the NRC commissioners. NU hopes to return Millstone 3 to service in the early spring of 1998 and Millstone 2 three to four months after Millstone 3. Millstone 1 is currently in extended maintenance status. Management cannot predict when the NRC will allow any of the Millstone units to return to service and thus cannot precisely estimate the total replacement power costs WMECO will ultimately incur. Replacement power costs incurred by WMECO attributable to the Millstone outages averaged approximately $5 million per month during 1997, and for 1998 are projected to average approximately $2 million per month for Millstone 3, $2 million per month for Millstone 2 and $1 million per month for Millstone 1 while the plants remain out of service. WMECO will continue to expense its replacement power costs in 1998. Based on the current estimates of expenditures and restart dates, management believes the NU system has sufficient resources to fund the restoration of the Millstone units and related replacement power costs. If the return to service of Millstone 3 or 2 is delayed substantially beyond the present restart estimates, if some financing facilities become unavailable because of difficulties in meeting borrowing conditions or renegotiating extensions, if CL&P and WMECO encounter additional significant costs or if any other significant deviations from management's assumptions occur, CL&P and WMECO could be unable to meet their cash requirements. In those circumstances, management would take even more stringent actions to reduce costs and cash outflows and attempt to obtain additional sources of funds. The availability of these funds would be dependent upon general market conditions and CL&P's and WMECO's respective credit and financial conditions at that time. For information regarding Millstone restart costs, see the MD&A. For information concerning the ability of WMECO to access its borrowing facilities, see the MD&A. Litigation: CL&P and WMECO, through NNECO as agent, operate Millstone 3 at cost, and without profit, under a sharing agreement that obligates them to utilize good utility operating practice and requires the joint owners to share the risk of employee negligence and other risks of operation and maintenance pro-rata in accordance with their ownership shares. This agreement also provides that CL&P and WMECO would be liable only for damages to the non-NU owners for a deliberate violation of the agreement pursuant to authorized corporate action. On August 7, 1997, the non-NU owners of Millstone 3 filed demands for arbitration with CL&P and WMECO as well as lawsuits in Massachusetts Superior Court against NU and its current and former trustees. The non-NU owners raise a number of contract, tort and statutory claims arising out of the operation of Millstone 3. The arbitrations and lawsuits seek to recover compensatory damages, punitive damages, treble damages and attorneys' fees. Owners representing approximately two-thirds of the non-NU interests in Millstone 3 claimed compensatory damages in excess of $200 million. In addition, one of the lawsuits seeks to restrain NU from disposing of its shares of the stock of WMECO and HWP, pending the outcome of the lawsuit. Management cannot estimate the potential outcome of these suits but believes there is no legal basis for the claims and intends to defend against them vigorously. To date, no reserves have been established for this litigation. At December 31, 1997, the costs related to this litigation for the NU system were estimated to be approximately $100 million for incremental O&M costs and approximately $100 million for replacement power costs. These costs are likely to increase as long as Millstone 3 remains out of service. C. ENVIRONMENTAL MATTERS The NU system is subject to regulation by federal, state and local authorities with respect to air and water quality, the handling and disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. The NU system has an active environmental auditing and training program and believes that it is in substantial compliance with current environmental laws and regulations. However, the NU system is subject to certain enforcement actions and governmental investigations in the environmental area. Management cannot predict the outcome of these enforcement acts and investigations. Environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations, and other facilities. Changing environmental requirements could also require extensive and costly modifications to WMECO's existing generating units, and transmission and distribution systems, and could raise operating costs significantly. As a result, WMECO may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation and transmission of electricity and the storage, transportation and disposal of by-products and wastes. WMECO may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. The cumulative long-term cost impact of increasingly stringent environmental requirements cannot be estimated accurately. WMECO has recorded a liability based upon currently available information for what it believes are its estimated environmental remediation costs that it expects to incur for waste disposal sites. In most cases, additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation and the possible effects of technological changes. At December 31, 1997, the net liability recorded by WMECO for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $1.6 million, which management has determined to be the most probable amount within the range of $1.6 million to $2.6 million. During 1997, WMECO adopted Statement of Position 96-1, "Environmental Remediation Liabilities" (SOP). The principal objective of the SOP is to improve the manner in which existing authoritative accounting literature is applied by entities to specific situations of recognizing, measuring and disclosing environmental remediation liabilities. The adoption of the SOP resulted in an increase of approximately $370 thousand to WMECO's environmental reserve in 1997. WMECO cannot estimate the potential liability for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws and regulatory practices, management does not believe the matters disclosed above will have a material effect on WMECO's financial position or future results of operations. D. NUCLEAR INSURANCE CONTINGENCIES Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities in the country covered by the federal government's third-party liability indemnification program, an owner of a nuclear unit could be assessed in proportion to its ownership interest in each of its nuclear units up to $75.5 million. Payments of this assessment would be limited to $10.0 million in any one year per nuclear incident based upon the owner's pro rata ownership interest in each of its nuclear units. In addition, the owner would be subject to an additional five percent or $3.8 million, in proportion to its ownership interests in each of its nuclear units, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection. Based upon its ownership interests in Millstone 1, 2 and 3, WMECO's maximum liability, including any additional assessments, would be $39.8 million per incident, of which payments would be limited to $5 million per year. In addition, through power purchase contracts with MYAPC, VYNPC, and CYAPC, WMECO would be responsible for up to an additional $11.9 million per incident, of which payments would be limited to $1.5 million per year. Insurance has been purchased to cover the primary cost of repair, replacement or decontamination of utility property resulting from insured occurrences. WMECO is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessment against WMECO with respect to losses arising during the current policy year is approximately $2.7 million under the primary property insurance program. Insurance has been purchased to cover certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences. WMECO is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessments against WMECO with respect to losses arising during current policy years are approximately $2.2 million under the replacement power policies and $3.8 million under the excess property damage, decontamination and decommissioning policies. The cost of a nuclear incident could exceed available insurance proceeds. Insurance has been purchased aggregating $200 million on an industry basis for coverage of worker claims. All participating reactor operators insured under this coverage are subject to retrospective assessments of $3 million per reactor. The maximum potential assessment against WMECO with respect to losses arising during the current policy period is approximately $2.2 million. Effective January 1, 1998, a new worker policy was purchased which is not subject to retrospective assessments. E. CONSTRUCTION PROGRAM The construction program is subject to periodic review and revision by management. WMECO currently forecasts construction expenditures of approximately $185 million for the years 1998-2002, including $27 million for 1998. In addition, WMECO estimates that nuclear fuel requirements, including nuclear fuel financed through the NBFT, will be approximately $56.4 million for the years 1998-2002, including $8.4 million for 1998. See Note 9, "Leases" for additional information about the financing of nuclear fuel. F. LONG-TERM CONTRACTUAL ARRANGEMENTS Yankee Companies: The NU system companies rely on VY for approximately 1.7 percent of their capacity under long-term contracts. Under the terms of their agreements, the NU system companies pay their ownership (or entitlement) shares of costs, which include depreciation, O&M expenses, taxes, the estimated cost of decommissioning and a return on invested capital. These costs are recorded as purchased power expense and are recovered through the companies' rates. WMECO's total cost of purchases under contracts with VYNPC amounted to $3.9 million in 1997, $4.1 million in 1996 and 1995. The other Yankee generating facilities, MY, CY and Yankee Rowe, were permanently shut down as of August 6, 1997, December 4, 1996 and February 26, 1992, respectively. See Note 2E, "Summary of Significant Accounting Policies--Investments and Jointly Owned Electric Utility Plant," for further information on the Yankee companies, and Note 3, "Nuclear Decommissioning," regarding the related decommissioning obligations. Nonutility Generators: WMECO has entered into various arrangements for the purchase of capacity and energy from nonutility generators (NUGs). These arrangements have terms from 15 to 25 years, currently expiring in the years 2008 through 2013, and requires WMECO to purchase energy at specified prices or formula rates. For the 12 months ending December 31, 1997, approximately 14 percent of NU system electricity requirements were met by NUGs. WMECO's total cost of purchases under these arrangements amounted to $31.2 million in 1997, $29.5 million in 1996, and $28.6 million in 1995. These costs may be deferred for eventual recovery through rates. Hydro-Quebec: Along with other New England utilities, WMECO, CL&P, PSNH and HWP have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. WMECO is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M and capital costs of these facilities. Estimated Annual Costs: The estimated annual costs of WMECO's significant long-term contractual arrangements are as follows: 1998 1999 2000 2001 2002 (Millions of Dollars) VYNPC ................... $ 4.9 $ 4.9 $ 4.8 $ 5.2 $ 5.4 NUGs .................... 35.1 36.8 39.5 41.6 43.8 Hydro-Quebec ............ 3.8 3.6 3.6 3.5 3.4 For additional information regarding the recovery of purchased power costs, see Note 2J, "Summary of Significant Accounting Policies - Recoverable Energy Costs." 13. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and nuclear decommissioning trusts: The carrying amounts approximate fair value. SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," requires investments in debt and equity securities to be presented at fair value. As a result of this requirement, the investments held in WMECO's nuclear decommissioning trust were adjusted to market by approximately $17.9 million as of December 31, 1997, and $8.4 million as of December 31, 1996, with a corresponding offset to the accumulated provision for depreciation. The amounts adjusted in 1997 and 1996 represent cumulative gross unrealized holding gains. The cumulative gross unrealized holding losses were immaterial for both 1997 and 1996. Preferred stock and long-term debt: The fair value of WMECO's fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amount of WMECO's financial instruments and the estimated fair values are as follows: Carrying Fair At December 31, 1997 Amount Value (Thousands of Dollars) Preferred stock not subject to mandatory redemption........................... $ 20,000 $ 16,252 Preferred stock subject to mandatory redemption............................ 21,000 20,580 Long-term debt - First Mortgage Bonds............ 304,800 302,627 Other long-term debt............................. 92,845 92,845 Carrying Fair At December 31, 1996 Amount Value (Thousands of Dollars) Preferred stock not subject to mandatory redemption........................... $ 20,000 $ 15,200 Preferred stock subject to mandatory redemption............................ 21,000 18,404 Long-term debt - First Mortgage Bonds............ 259,500 260,440 Other long-term debt............................. 90,855 90,855 The fair values shown above have been reported to meet the disclosure requirements and do not purport to represent the amounts at which those obligations would be settled. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Western Massachusetts Electric Company: We have audited the accompanying consolidated balance sheets, as restated - see Note 1, of Western Massachusetts Electric Company (a Massachusetts corporation and a wholly owned subsidiary of Northeast Utilities) and subsidiary as of December 31, 1997 and 1996, and the related consolidated statements of income, common stockholder's equity and cash flows, as restated - - see Note 1, for each of the three years in the period ended December 31, 1997. 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 Western Massachusetts Electric Company and subsidiary as of December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. Western Massachusetts Electric Company and Subsidiary As explained in Note 1 to the consolidated financial statements, the company has given retroactive effect to the change in accounting for nuclear compliance costs. ARTHUR ANDERSEN LLP Hartford, Connecticut February 20, 1998 (except with respect to the matter discussed in Note 1, as to which the date is June 10, 1998) MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This section contains management's assessment of WMECO's (the company) financial condition and the principal factors having an impact on the results of operations. The company is a wholly-owned subsidiary of Northeast Utilities (NU). This discussion should be read in conjunction with the company's consolidated financial statements and footnotes. FINANCIAL CONDITION OVERVIEW The length of the ongoing outages at the three Millstone nuclear plants (Millstone) and the high costs of the recovery efforts weakened WMECO's 1997 net income, balance sheet and cash flows and will continue to have an adverse impact on the company's financial condition until the units are returned to service. WMECO had a net loss of approximately $27 million in 1997, compared to net income of approximately $11 million in 1996. The poorer financial results in 1997 were due primarily to the fact that all three Millstone units were off line for the entire year in 1997 and spending associated with the recovery efforts was significantly higher in 1997 than it was in 1996. Millstone 3 operated for nearly three months in 1996 and Millstone 2 for nearly two months. As a result, the cost of replacing power ordinarily generated by the Millstone units rose by approximately $15 million in 1997. The total operation and maintenance (O&M) costs at Millstone were approximately $40 million higher in 1997. The higher Millstone costs have caused WMECO to focus closely on maintaining adequate liquidity and reducing non nuclear O&M costs. In July 1997, WMECO successfully sold $60 million of first mortgage bonds. WMECO's access to $90 million of revolving credit lines was renegotiated in the first half of 1997. Also helping to maintain liquidity was the renegotiation in early 1998 of a $100 million credit line used by Niantic Bay Fuel Trust (NBFT) to purchase nuclear fuel for Millstone. Additionally, non nuclear O&M expenses in 1997 were reduced by about $5 million from 1996. The SEC has advised WMECO to adjust for certain costs associated with the ongoing Millstone outages as they are incurred. For the past two years, WMECO has been reserving for the unavoidable costs they expected to incur to meet NRC requirements. These annual statements have been adjusted in accordance with the SEC's directive. Management does not expect implementation of this accounting change to affect the ability of The Connecticut Light and Power Company (CL&P) and WMECO to meet their financial covenants contained in their $313.75 million revolving credit arrangement. In 1998, management expects Millstone-related expenses to fall significantly, assuming Millstone 3 and Millstone 2 are returned to service at dates close to current estimates, although the O&M expenses at Millstone 3 and 2 will be considerably higher than before the station was placed on the Nuclear Regulatory Commission's (NRC's) watch list. The actual level of 1998 nuclear spending at Millstone will depend on when the units return to operation and the cost of restoring them to service. The company hopes to restart Millstone 3, the newest and largest unit at the site, in early spring of 1998 and Millstone 2 three to four months after Millstone 3. The company cannot restart the Millstone units until it receives formal approval from the NRC. As part of an effort to reduce spending in 1998, Millstone 1 has been placed in extended maintenance status. Management will review its options with respect to Millstone 1 in 1998, including restart, early retirement and other options. Rate reductions to customers served by the company are likely to offset a portion of the benefit of lower Millstone-related costs. On March 1, 1998, WMECO reduced retail rates by 10 percent in compliance with industry restructuring legislation passed in November 1997 by the Massachusetts Legislature. The 1997 Massachusetts legislation allowed full retail choice on March 1, 1998. WMECO expects to recover fully its stranded costs through a combination of securitization and divestiture of its non-nuclear generating assets. MILLSTONE OUTAGES WMECO has a 19-percent ownership interest in Millstone units 1 and 2 and a 12.24-percent ownership interest in Millstone unit 3. Millstone 1, 2 and 3 have been out of service since November 4, 1995, February 21, 1996, and March 30, 1996, respectively. Subsequent to its January 31, 1996, announcement that Millstone had been placed on its watch list, the NRC has stated that the units cannot return to service until independent, third-party verification teams have reviewed the actions taken to improve the design, configuration and employee concern issues that prompted the NRC to place the units on its watch list. The actual date of the return to service for each of the units is dependent upon the completion of independent inspections, reviews by the NRC and a vote by the NRC Commissioners. In January 1998, NU declared Millstone 3 physically ready for restart, which meant that almost all of the restart-required physical work had been completed in the plant. The NRC currently is conducting a series of inspections to determine, among other things, whether the plant has effective leadership and corrective action and employee concerns programs. The Independent Corrective Action Verification Program, an NRC-ordered independent review of the plant's design and licensing bases, is expected to be completed in March 1998. In 1997, WMECO's share of nonfuel O&M costs expensed for Millstone increased to approximately $104 million, compared to approximately $64 million in 1996. Replacement power costs attributable to the Millstone outages totaled approximately $56 million in 1997 compared to $41 million expensed in 1996. These costs for 1998 are forecasted to average approximately $2 million per month for Millstone 3, $2 million per month for Millstone 2 and $1 million per month for Millstone 1 while the plants are out of service. The company has been, and will continue to be, expensing all of the costs to restart the units including replacement power and nonfuel O&M expenses. NU and its subsidiaries are involved in several class action lawsuits and other litigation in connection with their nuclear operations. See the "Notes to Consolidated Financial Statements," Note 12B, for further information on this litigation. MILLSTONE 1 Management will review its options with respect to Millstone 1 during 1998. The issues that management will consider in evaluating its options include the costs to restart the unit and the economic benefits of the unit's continued operation. CAPACITY During 1996 and continuing into 1997, WMECO took measures to improve its capacity position, including obtaining additional generating capacity, improving the availability of the company's generating units and improving the company transmission capability. During 1997, WMECO spent approximately $10 million to ensure availability of adequate generating generating capacityin Connecticut, of which $6 million was expensed. During 1998 these costs are expected to be approximately $11 million. In 1998, WMECO does not anticipate the need to take additional measures to ensure adequate generating capacity. LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations decreased approximately $41 million in 1997, compared to 1996, primarily due to higher cash expenditures related to the Millstone outages, and the pay down in 1997 of the 1996 year end accounts payable balance. The 1996 year end accounts payable balance was relatively high due to costs related to a severe December storm and costs associated with the Millstone outages that had been incurred but not yet paid by the end of 1996. Net cash from financing activities increased approximately $44 million, primarily due to the issuance of long-term debt in 1997 and lower reacquisitions and retirements of long-term debt and preferred stock, partially offset by the repayment of short-term debt. WMECO established facilities in 1996 under which they may sell, from time to time, up to $40 million, of its accounts receivable and accrued utility revenues. As of December 31, 1997, WMECO sold approximately $20 million of receivables to third-party purchasers. NU's, WMECO's and CL&P's three-year revolving credit agreement (Credit Agreement) was amended in May 1997 (the Credit Agreement). Under the Revolving Credit Agreement, CL&P and WMECO are able to borrow up to approximately $225 million and $90 million, respectively, subject to a total borrowing limit of $313.75 million for all three borrowers. NU will be able to borrow up to $50 million when NU, CL&P and WMECO have each maintained a consolidated operating income to consolidated interest expense ratio of at least 2.50 to 1 for two consecutive fiscal quarters. Currently, the companies cannot meet this requirement. At December 31, 1997, WMECO had $15 million outstanding under the New Credit Agreement. Each major subsidiary of NU finances its own needs. Neither CL&P nor WMECO has any financing agreements containing cross defaults based on financial defaults by NU, Public Service Company of New Hampshire (PSNH) or North Atlantic Energy Corporation (NAEC). Nevertheless, it is possible that investors will take negative operating results or regulatory developments for one subsidiary of NU into account when evaluating the other NU subsidiaries. That could, as a practical matter and despite the contractual and legal separations among NU and its subsidiaries, negatively affect the company's access to financial markets. In December 1997 and January 1998, Moody's Investors Service (Moody's) and Standard & Poor's (S&P), respectively, downgraded the senior secured debt of CL&P, WMECO and NU, as well as the preferred stock of CL&P and WMECO. This was the fourth time Moody's and S&P have downgraded CL&P and WMECO securities since the Millstone units went on the NRC watch list in 1996. All of the NU system's securities are rated below investment grade and remain under review for further downgrade. Although WMECO does not have any plans to issue debt in the near term, rating agency downgrades generally increase the future cost of borrowing funds because lenders will want to be compensated for increased risk. Additionally, this could also affect the terms and ability of the company to extend existing agreements. The downgrade by Moody's of WMECO's first mortgage bonds to Ba2 in December 1997 brought those ratings to a level at which the sponsor of WMECO's accounts receivable program can take various actions, in its discretion, which would have the practical effect of limiting WMECO's ability to utilize the facility. The WMECO accounts receivable program could be terminated if WMECO's first mortgage bond credit ratings experience one more level of downgrade. WMECO's ability to borrow under the financing arrangements is dependent on the satisfaction of contractual borrowing conditions. The financial covenants that must be satisfied to permit WMECO to borrow under the New Credit Agreement are particularly restrictive and become more restrictive throughout 1998. Spending levels in 1998, particularly for the first half of the year while the Millstone units are expected to be out of service, have been, and will be constrained to levels intended to assure that the financial covenants in WMECO's Credit Agreement are satisfied. However, there is no assurance that these financial covenants will be met as the system may encounter additional unexpected costs from such areas as storms, reduced revenues from regulatory actions or the effect of weather on sales levels. If the return to service of Millstone 3 or Millstone 2 is delayed substantially beyond the present restart estimates, if some borrowing facilities become unavailable because of difficulties in meeting borrowing conditions or renegotiating extensions, if the system encounters additional significant costs, or any other significant deviations from management's current assumptions, the currently available borrowing facilities could be insufficient to meet all of WMECO's cash requirements. In those circumstances, management would take even more stringent actions to reduce costs and cash outflows and would attempt to take other actions to obtain additional sources of funds. The availability of these funds would be dependent upon the general market conditions and WMECO's credit and financial condition at that time. RESTRUCTURING On November 25, 1997, Massachusetts enacted a comprehensive electric utility industry restructuring bill. The bill provides that each Massachusetts electric company, including WMECO, will decrease its rates by 10 percent and allow all its customers to choose their retail electric supplier on March 1, 1998. The statute requires a further 5 percent rate reduction, adjusted for inflation, by September 1, 1999. In addition, the legislation provides, among other things, for: (i) recovery of stranded costs through a "transition charge" to customers, subject to review by the Department of Telecommunications and Energy (DTE), formerly the Department of Public Utilities (DPU, collectively the DTE), (ii) a possible limitation on WMECO's return on equity should its transition cost charge go above a certain level, (iii) securitization of allowed strandable costs, and (iv) divestiture of nonnuclear generation. WMECO hopes it will be able to complete securitization in 1998. The statute also provides that an electric company must transfer or separate ownership of generation, transmission and distribution facilities into independent affiliates or functionally separate such facilities within 30 business days after federal approval. Additionally, marketing companies formed by an electric company are to be separate from the electric company and separate from generation, transmission or distribution affiliates. On December 31, 1997, WMECO filed its restructuring plan with the DTE consistent with the Massachusetts restructuring legislation. The plan sets out the process by which WMECO, as of March 1, 1998, initiated a 10 percent rate reduction for all customer rate classes and allowed customers to choose their energy supplier. WMECO intends to mitigate its strandable costs through several steps, including divesting WMECO's nonnuclear generating plants at an auction to be held as soon as June 30, 1998, and securitization of approximately $500 million of stranded costs. NU intends to participate through a nonregulated affiliate in the competitive bid process for WMECO's generation resources. Any proceeds in excess of book value received from the divestiture of these units will be used to mitigate stranded costs. As required by the legislation, WMECO will continue to operate and maintain the transmission and local distribution network and deliver electricity to all customers. On February 20, 1998, the DTE issued an order approving, in all material respects, WMECO's restructuring plan on an interim basis. A final decision is expected in 1998. Because WMECO is obligated to reduce rates on March 1, 1998, before the means of financing for restructuring are completed, WMECO's cash flows and financial condition will be negatively affected. These impacts would become significant if there are material delays in, or significantly reduced proceeds from, the divestiture of nonnuclear generation and securitization. See the "Notes to Consolidated Financial Statements," Note 12A, for the potential accounting impacts of restructuring. RATE MATTERS In April, 1996, the DTE approved a settlement (the Agreement) that included the continuation through February 1998 of a 2.4 percent rate reduction instituted in June 1994. Additionally, the Agreement terminated certain pending and potential reviews of WMECO's generating plant performance and accelerated its amortization of strandable generation assets by approximately $6 million in 1996 and $10 million in 1997. On August 20, 1997, WMECO filed with the DTE a joint motion for approval of a settlement agreement with the Massachusetts Attorney General for a fuel adjustment clause (FAC) which would allow for a lower rate to WMECO customers for the billing months of September 1997 through February 1998. WMECO is not recovering replacement power costs during this period and has indicated that it would not seek recovery of any of replacement power costs associated with the Millstone outages. WMECO has been expensing and will continue to expense these costs. The Massachusetts restructuring legislation effectively eliminates the FAC, effective March 1, 1998. NUCLEAR DECOMMISSIONING CONNECTICUT YANKEE WMECO has a 9.5 percent ownership interest in the Connecticut Yankee nuclear generating facility (CY or the plant). On December 4, 1996, the Board of Directors of Connecticut Yankee Atomic Power Company voted unanimously to cease permanently the production of power at the plant. The decision to retire CY from commercial operation was based on an economic analysis of the costs of operating it compared to the costs of closing it and incurring replacement power costs over the remaining period of the plant's operating license, which would have expired in 2007. The economic analysis showed that closing the plant and incurring replacement power costs produced substantial savings. CY has undertaken a number of regulatory filings intended to implement the decommissioning. In late December 1996, CY filed an amendment to its power contracts with the FERC to clarify the obligations of its purchasing utilities following the decision to cease power production. At December 31, 1997, WMECO's share of these obligations was approximately $59 million, including the cost of decommissioning and the recovery of existing assets. Management expects that the company will continue to be allowed to recover such FERC approved costs from its customers. Accordingly, WMECO has recognized its share of the estimated costs as a regulatory asset, with a corresponding obligation, on its balance sheets. MAINE YANKEE (MY) WMECO has a 3 percent ownership interest in the Maine Yankee (MY) nuclear generating facility. On August 6, 1997, the Board of Directors of Maine Yankee Atomic Power Company (MYAPC) voted unanimously to retire MY. On January 14, 1998, FERC released a draft order on the MYAPC application to amend its power contracts with the owner/purchasers and revise its decommissioning and other charges. FERC has accepted the proposed application for filing and made the amendments and the proposed charges under the contracts effective on January 15, 1998, subject to refund after hearings. At December 31, 1997, WMECO'S share of the estimated remaining obligation, including decommissioning, amounted to approximately $26 million. Under the terms of the contracts with MYAPC, the shareholders' sponsor companies, including WMECO, are responsible for their proportionate share of the costs of the unit, including decommissioning. Management expects that WMECO will be allowed to recover these costs from its customers. Accordingly, WMECO has recognized these costs as a regulatory asset, with a corresponding obligation on its balance sheet. MILLSTONE WMECO's estimated cost to decommission its share of the Millstone plants is approximately $242 million in year end 1997 dollars. These costs are being recognized over the lives of the respective units with a portion being currently recovered through rates. As of December 31, 1997, the market value of the contributions already made to the decommissioning trusts, including their investment returns, was approximately $103 million. See the "Notes to Consolidated Financial Statements," Note 3, for further information on nuclear decommissioning. ENVIRONMENTAL MATTERS WMECO is potentially liable for environmental cleanup costs at a number of sites inside and outside its service territory. To date, the future estimated environmental remediation liability has not been material with respect to the earnings or financial position of WMECO. At December 31, 1997, WMECO had recorded an environmental reserve of approximately $1.4 million. See the "Notes to Consolidated Financial Statements," Note 12C, for further information on environmental matters. YEAR 2000 ISSUE The Year 2000 issue exists because many computer systems and applications currently use two-digit date fields to designate a year. As the change of the century occurs, date-sensitive systems may recognize the year 2000 as 1900, or not recognize it at all. This inability to recognize or properly treat the year 2000 may cause NU's systems to process critical financial and operational information incorrectly. The NU system has assessed and continues to assess the impact of the Year 2000 issue on its operating and reporting systems. The assessment of the nuclear operating systems is continuing and is expected to be completed in the summer of 1998. The NU System will utilize both internal and external resources to reprogram or replace, and test the software for Year 2000 modifications. The total estimated remaining cost of the Year 2000 project for the NU system is $37 million and is being funded through operating cash flows. This estimate does not include any costs for the replacement or repair of equipment or devices that may be identified during the assessment process. The majority of these costs will be expensed as incurred over the next two years. To date, the NU system has incurred and expensed approximately $4 million related to the assessment of and preliminary efforts in connection with its Year 2000 project. The costs of the project and the date on which the NU system plans to complete the Year 2000 modifications are based on management's best estimates, which were derived utilizing numerous assumptions of future events, including the continued availability of certain resources, third-party modification plans and other factors. However, there can be no guarantee that these estimates will be achieved, and actual results could differ materially from those plans. If the NU system's remediation plan is not successful, there could be a significant disruption of the company's operations. RESULTS OF OPERATIONS Income Statement Variances Millions of Dollars 1997 over/(under) 1996 1996 over/(under) 1995 Amount Percent Amount Percent Operating revenues $ 5 1% $ 1 - % Fuel, purchased and net interchange power 25 22 29 33 Other operation 17 12 (6) (4) Maintenance 25 45 19 50 Amortization of regulatory assets, net (3) (30) (10) (53) Federal and state income taxes (26) (a) (4) (31) Other income, net (2) (a) - - Interest on long-term debt 2 8 (3) (10) Net income (39) (a) (28) (72) (a) Percentage greater than 100 OPERATING REVENUES Total operating revenues increased in 1997, primarily due to higher transmission and capacity revenues and higher retail revenues. Retail revenues were higher due to lower price discounts to customers, partially offset by lower retail sales. Retail kilowatt-hour sales were 1 percent lower in 1997 primarily as a result of mild winter weather. Total operating revenues increased in 1996, primarily due to higher retail sales, partially offset by lower fuel and conservation recoveries. Retail kilowatt-hour sales increased 2.7 percent ($9 million) primarily due to modest economic growth in 1996. Fuel recoveries decreased $6 million, primarily due to the timing of the recovery of costs under the company's fuel clause. Conservation recoveries decreased approximately $6 million primarily due to lower demand side management costs. FUEL, PURCHASED AND NET INTERCHANGE POWER Fuel, purchased and net interchange power expense increased in 1997, primarily due to replacement power costs associated with the Millstone outages. Fuel, purchased and net interchange power expense increased in 1996, primarily due to higher replacement power associated with the Millstone outages, partially offset by the timing of the recognition of costs under the company's fuel clause and lower nuclear generation. OTHER OPERATION AND MAINTENANCE Other operation and maintenance expenses increased in 1997, primarily due to higher costs associated with the Millstone restart effort ($40 million), higher capacity charges from Maine Yankee ($2 million) and higher costs to ensure adequate capacity ($6 million), partially offset by lower capacity charges from Connecticut Yankee as a result of a property tax refund ($4 million) and lower administrative and general expenses ($5 million) primarily due to lower pensions and benefit costs. Other operation and maintenance expenses increased in 1996, primarily due to higher costs associated with the Millstone restart effort ($21 million), partially offset by lower costs for demand side management programs and a 1995 work stoppage. AMORTIZATION OF REGULATORY ASSETS, NET Amortization of regulatory assets, net decreased in 1997, primarily due to the completion of the amortization of the Millstone 3 unuseful investment in 1996. Amortization of regulatory assets, net decreased in 1996, primarily due to the completion of the amortization of the Millstone 3 phase-in plans in 1995 and unuseful investment in June, 1996, partially offset by higher amortization as a result of the 1996 rate settlement. FEDERAL AND STATE INCOME TAXES Federal and state income taxes decreased in 1997, primarily due to lower book taxable income. Federal and state income taxes decreased in 1996, primarily due to lower book taxable income, partially offset by 1995 tax benefits from a favorable tax ruling and the expiration of the 1991 federal statute of limitations. OTHER INCOME, NET Other income, net decreased in 1997, primarily due to costs associated with the accounts receivable facility. INTEREST ON LONG-TERM DEBT Interest on long-term debt increased in 1997 due to the issuance of additional long-term debt. Interest on long-term debt decreased in 1996, primarily due to lower average interest rates as a result of refinancing activities and lower average 1996 debt levels. Western Massachusetts Electric Company and Subsidiary SELECTED FINANCIAL DATA (a) 1997 1996 1995 1994 1993 (Restated) (Restated) (Thousands of Dollars) Operating Revenues...$ 426,447 $ 421,337 $ 420,434 $ 421,477 $ 415,055 Operating Income.... 251 33,190 63,064 70,940 60,348 Net (Loss)/Income.... (27,460) 11,089 39,133 49,457 40,594(b) Cash Dividends on Common Stock....... 15,004 16,494 30,223 29,514 28,785 Total Assets......... 1,179,128 1,191,915 1,142,346 1,183,618 1,204,642 Long-Term Debt (c)... 396,649 349,442 347,470 379,969 393,232 Preferred Stock Not Subject to Mandatory Redemption.......... 20,000 20,000 53,500 68,500 73,500 Preferred Stock Subject to Mandatory Redemption(c)....... 21,000 21,000 24,000 24,675 27,000 Obligations Under Capital Leases(c)... 32,887 32,234 36,011 36,797 36,902 (a) Reclassifications of prior data have been made to conform with the current presentation. (b) Includes the cumulative effect of change in accounting for municipal property tax expense, which increased earnings for common shares by $3.9 million. (c) Includes portion due within one year. STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) (Restated) Quarter Ended (a) 1997 March 31 June 30 Sept. 30 Dec. 31 Operating Revenues........ $106,054 $104,130 $111,166 $105,097 Operating Income/(Loss)... $ 675 $ (4,794) $ 1,875 $ 2,495 Net Loss.................. $ (5,033) $(11,492) $ (5,303) $ (5,632) 1996 Operating Revenues........ $114,797 $102,602 $ 99,866 $104,072 Operating Income ......... $ 18,004 $ 10,522 $ 3,441 $ 1,223 Net Income/(Loss)......... $ 12,421 $ 5,161 $ (1,282) $ (5,211) STATISTICS Gross Electric Average Utility Plant Annual December 31, Use Per Electric (Thousands kWh Sales Residential Customers Employees of Dollars) (Millions) Customer (kWh) (Average) (December 31) 1997 $1,334,233 4,300 7,121 195,324 507 1996 1,303,361 4,626 7,335 194,705 497 1995 1,285,269 4,846 7,105* 193,964 527 1994 1,271,513 4,978 7,433 193,187 617 1993 1,242,927 4,715 7,351 192,542 657 *Effective January 1, 1996, the amounts shown reflect billed and unbilled sales. 1995 has been restated to reflect this change. EX-13.4 5 ANNUAL REPORT OF PSNH EXHIBIT 13.4 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AMENDED 1997 ANNUAL REPORT Public Service Company of New Hampshire Amended 1997 Annual Report Index Contents Page Balance Sheets (Restated).......................................... 2 Statements of Income (Restated).................................... 4 Statements of Cash Flows (Restated)................................ 5 Statements of Common Stockholder's Equity (Restated)............... 6 Notes to Financial Statements (Restated)........................... 7 Report of Independent Public Accountants........................... 40 Management's Discussion and Analysis of Financial Condition and Results of Operations (Restated)................... 42 Selected Financial Data (Restated)................................. 50 Statistics......................................................... 52 Statements of Quarterly Financial Data (Restated).................. 52 Preferred Stockholder and Bondholder Information................... Back Cover PART I. FINANCIAL INFORMATION PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE BALANCE SHEETS
- ----------------------------------------------------------------------------------------- At December 31, 1997 1996 (Restated) (Restated) - ----------------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS - ------ Utility Plant, at cost: Electric................................................ $ 1,898,319 $ 1,877,955 Less: Accumulated provision for depreciation......... 590,056 552,780 ------------- ------------- 1,308,263 1,325,175 Unamortized acquisition costs........................... 402,285 491,709 Construction work in progress........................... 10,716 11,032 Nuclear fuel, net....................................... 1,308 1,313 ------------- ------------- Total net utility plant............................. 1,722,572 1,829,229 ------------- ------------- Other Property and Investments: Nuclear decommissioning trusts, at market............... 4,332 3,229 Investments in regional nuclear generating companies and subsidiary company, at equity............ 19,169 19,578 Other, at cost.......................................... 3,773 1,835 ------------- ------------- 27,274 24,642 ------------- ------------- Current Assets: Cash and cash equivalents............................... 94,459 1,015 Notes receivable from affiliated companies.............. - 18,250 Receivables, less accumulated provision for uncollectible accounts of $1,702,000 in 1997 and of $1,700,000 in 1996............................. 89,338 105,381 Accounts receivable from affiliated companies........... 38,520 32,452 Accrued utility revenues................................ 36,885 36,317 Fuel, materials, and supplies, at average cost.......... 40,161 44,852 Recoverable energy costs, net--current portion.......... 31,886 - Prepayments and other................................... 11,271 24,629 ------------- ------------- 342,520 262,896 ------------- ------------- Deferred Charges: Regulatory assets....................................... 695,418 684,504 Deferred receivable from affiliated company............. 32,472 33,284 Unamortized debt expense................................ 11,749 12,731 Other................................................... 5,154 3,926 ------------- ------------- 744,793 734,445 ------------- ------------- Total Assets........................................ $ 2,837,159 $ 2,851,212 ============= =============
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE BALANCE SHEETS
- ----------------------------------------------------------------------------------------- At December 31, 1997 1996 (Restated) (Restated) - ----------------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock--$1 par value. Authorized and outstanding 1,000 shares................ $ 1 $ 1 Capital surplus, paid in................................ 423,713 423,058 Retained earnings (Note 1).............................. 170,501 175,254 ------------- ------------- Total common stockholder's equity.............. 594,215 598,313 Preferred stock subject to mandatory redemption......... 75,000 100,000 Long-term debt.......................................... 516,485 686,485 ------------- ------------- Total capitalization........................... 1,185,700 1,384,798 ------------- ------------- Obligations Under Seabrook Power Contracts and Other Capital Leases................................. 799,450 871,707 ------------- ------------- Current Liabilities: Long-term debt and preferred stock--current portion..... 195,000 25,000 Obligations under Seabrook Power Contracts and other capital leases--current portion........................ 122,363 42,910 Accounts payable........................................ 21,231 37,675 Accounts payable to affiliated companies................ 32,677 31,130 Accrued taxes........................................... 69,445 81 Accrued interest........................................ 7,197 7,992 Accrued pension benefits................................ 46,061 44,790 Other................................................... 9,417 36,616 ------------- ------------- 503,391 226,194 ------------- ------------- Deferred Credits: Accumulated deferred income taxes....................... 204,406 258,654 Accumulated deferred investment tax credits............. 3,972 4,511 Deferred contractual obligations........................ 83,042 50,271 Deferred revenue from affiliated company................ 32,472 33,284 Other................................................... 24,726 21,793 ------------- ------------- 348,618 368,513 ------------- ------------- Commitments and Contingencies (Note 11) ------------- ------------- Total Capitalization and Liabilities........... $ 2,837,159 $ 2,851,212 ============= =============
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF INCOME
- -------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) - -------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues................................. $1,108,459 $1,110,169 $ 979,971 ----------- ----------- ---------- Operating Expenses: Operation -- Fuel, purchased and net interchange power..... 326,745 356,679 257,008 Other......................................... 368,363 326,337 313,604 Maintenance...................................... 38,320 45,728 42,244 Depreciation..................................... 44,377 42,983 44,337 Amortization of regulatory assets, net........... 56,557 56,884 55,547 Federal and state income taxes................... 86,450 80,677 69,817 Taxes other than income taxes.................... 43,623 45,123 41,786 ----------- ----------- ---------- Total operating expenses (Note 1).......... 964,435 954,411 824,343 ----------- ----------- ---------- Operating Income................................... 144,024 155,758 155,628 ----------- ----------- ---------- Other Income: Equity in earnings of regional nuclear generating companies and subsidary company..... 1,373 2,075 1,645 Other, net....................................... 698 8,075 3,162 Income taxes..................................... (2,391) (7,723) (770) ----------- ----------- ---------- Other (loss)/income, net................... (320) 2,427 4,037 ----------- ----------- ---------- Income before interest charges............. 143,704 158,185 159,665 ----------- ----------- ---------- Interest Charges: Interest on long-term debt....................... 51,259 57,557 76,320 Other interest................................... 273 3,163 90 ----------- ----------- ---------- Interest charges, net...................... 51,532 60,720 76,410 ----------- ----------- ---------- Net Income (Note 1)................................ $ 92,172 $ 97,465 $ 83,255 =========== =========== ==========
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) - -------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Activities: Net Income.................................................. $ 92,172 $ 97,465 $ 83,255 Adjustments to reconcile to net cash from operating activities: Depreciation.............................................. 44,377 42,983 44,337 Deferred income taxes and investment tax credits, net..... 21,645 94,983 69,986 Recoverable energy costs, net of amortization............. (12,336) 31,663 (15,266) Amortization of acquisition costs......................... 56,557 56,884 55,547 Deferred Seabrook capital costs........................... (8,376) - - Other sources of cash..................................... 51,054 65,922 15,973 Other uses of cash........................................ (67,590) (51,188) - Changes in working capital: Receivables and accrued utility revenues.................. 9,407 (36,907) (10,506) Fuel, materials and supplies.............................. 4,691 (3,135) (4,264) Accounts payable.......................................... (14,897) (7,714) 2,375 Accrued taxes............................................. 69,364 (717) (3,506) Other working capital (excludes cash)..................... (13,365) (13,559) 16 ----------- ----------- ----------- Net cash flows from operating activities (Note 1)............. 232,703 276,680 237,947 ----------- ----------- ----------- Financing Activities: Reacquisitions and retirements of long-term debt............ - (172,500) (141,000) Reacquisitions and retirements of preferred stock........... (25,000) - - Cash dividends on preferred stock........................... (11,925) (13,250) (13,250) Cash dividends on common stock.............................. (85,000) (52,000) (52,000) ----------- ----------- ----------- Net cash flows used for financing activities.................. (121,925) (237,750) (206,250) ----------- ----------- ----------- Investment Activities: Investment in plant: Electric utility plant.................................... (33,570) (37,480) (46,672) Nuclear fuel.............................................. 5 129 (184) ----------- ----------- ----------- Net cash flows used for investments in plant................ (33,565) (37,351) (46,856) NU System Money Pool........................................ 18,250 850 15,900 Investment in nuclear decommissioning trusts................ (490) (521) (489) Other investment activities, net............................ (1,529) (1,010) (431) ----------- ----------- ----------- Net cash flows used for investments........................... (17,334) (38,032) (31,876) ----------- ----------- ----------- Net Increase/(Decrease) in Cash For The Period................ 93,444 898 (179) Cash - beginning of period.................................... 1,015 117 296 ----------- ----------- ----------- Cash - end of period.......................................... $ 94,459 $ 1,015 $ 117 =========== =========== =========== Supplemental Cash Flow Information: Cash paid/(refunded) during the year for: Interest, net of amounts capitalized........................ $ 51,775 $ 58,835 $ 74,543 =========== =========== =========== Income taxes................................................ $ 10,612 $ (457) $ 1,369 =========== =========== =========== Increase in obligations: Seabrook Power Contracts and other capital leases........... $ 6,197 $ 93 $ 28,028 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- --------------------------------------------------------------------------------------- Capital Retained Common Surplus, Earnings Stock Paid In (Note 1) Total - --------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1995............... $ 1 $421,784 $125,034 $546,819 Net income for 1995.................. 83,255 83,255 Cash dividends on preferred stock.... (13,250) (13,250) Cash dividends on common stock....... (52,000) (52,000) Capital stock expenses, net.......... 601 601 -------- --------- --------- --------- Balance at December 31, 1995............. 1 422,385 143,039 565,425 Net income for 1996 (Note 1)......... 97,465 97,465 Cash dividends on preferred stock.... (13,250) (13,250) Cash dividends on common stock....... (52,000) (52,000) Capital stock expenses, net.......... 673 673 -------- --------- --------- --------- Balance at December 31, 1996 (Restated).. 1 423,058 175,254 598,313 Net income for 1997 (Note 1)......... 92,172 92,172 Cash dividends on preferred stock.... (11,925) (11,925) Cash dividends on common stock....... (85,000) (85,000) Capital stock expenses, net.......... 655 655 -------- --------- --------- --------- Balance at December 31, 1997 (Restated).. $ 1 $423,713 $170,501 $594,215 ======== ========= ========= =========
The accompanying notes are an integral part of these financial statements. Public Service Company of New Hampshire NOTES TO FINANCIAL STATEMENTS 1. SECURITIES AND EXCHANGE COMMISSION INQUIRY In a letter dated March 25, 1998, the Securities and Exchange Commission (SEC) inquired into Northeast Utilities' (NU) accounting for nuclear compliance costs. These costs are the unavoidable incremental costs associated with the current nuclear outages required to be incurred prior to restart of the units in accordance with correspondence received from the Nuclear Regulatory Commission (NRC) early in 1996. The SEC's view is that these unavoidable costs associated with nuclear outages and procedures to be implemented at nuclear power plants in response to regulatory requirements required prior to restart of the units should be expensed as incurred. During 1996 and 1997, NU and its wholly owned subsidiaries, The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO), reserved for these unavoidable incremental costs that they expected to incur to meet NRC standards. The SEC advised NU, CL&P, PSNH and WMECO to reflect these costs as they are incurred. While NU and its independent auditors, Arthur Andersen LLP, believed the accounting was required by, and was in accordance with, generally accepted accounting principles, NU has agreed to adjust its accounting for nuclear compliance costs and amend its 1996 and 1997 Form 10-K filings. The financial statements in this report have been restated to reflect the change in accounting. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. ABOUT PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE Public Service Company of New Hampshire (PSNH or the company), CL&P, WMECO, North Atlantic Energy Corporation (NAEC), and Holyoke Water Power Company (HWP) are the operating subsidiaries comprising the Northeast Utilities system (the NU system) and are wholly owned by NU. The NU system furnishes franchised retail electric service in Connecticut, New Hampshire, and western Massachusetts through CL&P, PSNH, WMECO, and HWP. A fifth subsidiary, NAEC, sells all of its entitlement to the capacity and output of the Seabrook nuclear generating unit (Seabrook, a 1,148-megawatt (MW) nuclear generating unit) to PSNH under two long-term contracts (the Seabrook Power Contracts). In addition to its franchised retail service, the NU system furnishes firm and other wholesale electric services to various municipalities and other utilities, and participates in limited retail access programs, providing off-system retail electric service. The NU system serves about 30 percent of New England's electric needs and is one of the 25 largest electric utility systems in the country as measured by revenues. Other wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing and other services to the NU system companies. North Atlantic Energy Service Corporation (NAESCO) acts as agent for CL&P and NAEC, and has operational responsibilities for Seabrook. Northeast Nuclear Energy Company (NNECO) acts as agent for the NU system companies and other New England utilities in operating the Millstone nuclear generating facilities. B. PRESENTATION The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity and are subject to approval by various federal and state regulatory agencies. C. PUBLIC UTILITY REGULATION NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act). NU and its subsidiaries, including PSNH, are subject to the provisions of the 1935 Act. Arrangements among the NU system companies, outside agencies and other utilities covering inter- connections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. PSNH is subject to further regulation for rates, accounting and other matters by the FERC and/or the applicable state regulatory commissions. For information regarding proposed changes in the nature of industry regulation, see Note 11A, "Commitments and Contingencies - Restructuring and Rate Matters." D. NEW ACCOUNTING STANDARDS The Financial Accounting Standards Board (FASB) issued a new accounting standard in February 1997: Statement of Financial Accounting Standards (SFAS) 129, "Disclosure of Information about Capital Structure." SFAS 129 establishes standards for disclosing information about an entity's capital structure. PSNH's current disclosures are consistent with the requirements of SFAS 129. During June 1997, the FASB issued SFAS 130, "Reporting Comprehensive Income" and SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." SFAS 130 establishes standards for the reporting and disclosure of comprehensive income. To date, the NU system companies have not had material transactions that would be required to be reported as comprehensive income. SFAS 131 determines the standards for reporting and disclosing qualitative and quantitative information about a company's operating segments. This information includes segment profit or loss, certain segment revenue and expense items and segment assets and a reconciliation of these segment disclosures to corresponding amounts in the company's general purpose financial statements. Management performance is currently evaluated using a cost- based budget and the information required by SFAS 131 is not available. Therefore, these disclosure requirements are not applicable. Management believes that the implementation of SFAS 130 and SFAS 131 will not have a material impact on PSNH's current disclosures. See Note 11C, "Commitments and Contingencies-Environmental Matters," for information on other newly issued accounting and reporting standards related to this area. E. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT Regional Nuclear Generating Companies: PSNH owns common stock of four regional nuclear generating companies (Yankee companies). PSNH's investments in the Yankee companies are accounted for on the equity basis due to PSNH's ability to exercise significant influence over their operating and financial policies. The Yankee companies, with PSNH's ownership interests, are: Connecticut Yankee Atomic Power Company (CYAPC) ................ 5.0% Yankee Atomic Electric Company (YAEC) .......................... 7.0 Maine Yankee Atomic Power Company (MYAPC) ...................... 5.0 Vermont Yankee Nuclear Power Corporation (VYNPC) ............... 4.0 PSNH's equity investments in the Yankee companies at December 31, 1997 are: (Thousands of Dollars) CYAPC .............................................. $ 5,761 YAEC ............................................... 1,427 MYAPC .............................................. 3,880 VYNPC .............................................. 2,085 $13,153 Each Yankee company owns a single nuclear generating unit. Under the terms of the contracts with the Yankee companies, the shareholders- sponsors, including PSNH, are responsible for their proportionate share of the costs of each unit, including decommissioning. The energy and capacity costs from VYNPC and nuclear decommissioning costs of the Yankee companies that have been shut down are billed as purchased power to PSNH. The electricity produced by the Vermont Yankee nuclear generating facility (VY) is committed substantially on the basis of ownership interests and is billed pursuant to contractual agreements. YAEC's, CYAPC's and MYAPC's nuclear power plants were shut down permanently on February 26, 1992, December 4, 1996, and August 6, 1997, respectively. Under ownership agreements with the Yankee companies, PSNH may be asked to provide direct or indirect financial support for one or more of the companies. For more information on the Yankee companies, see Note 5, "Nuclear Decommissioning," and Note 11F, "Commitments and Contingencies - Long-Term Contractual Arrangements." Millstone 3: PSNH has a 2.85 percent joint ownership interest in Millstone 3, a 1,154-MW nuclear generating unit. As of December 31, 1997 and 1996, plant-in-service included approxi-mately $118.7 million and the accumulated provision for depreciation included approximately $32.3 million and $29.4 million, respectively, for PSNH's share of Millstone 3. PSNH's share of Millstone 3 expenses is included in the corresponding operating expenses on the accompanying Statements of Income. The Millstone 3 unit is out of service. NU hopes to return Millstone 3 to service in early spring of 1998. For more information on the Millstone 3 unit, see Note 11B, "Commitments and Contingencies - Nuclear Performance." Wyman Unit 4: PSNH has a 3.14 percent ownership interest in Wyman Unit 4 (Wyman), a 632-MW oil-fired generating unit. At December 31, 1997 and 1996, plant-in-service included approximately $6.0 million, respectively and the accumulated provision for depreciation included approximately $3.9 million and $3.7 million, respectively, for PSNH's share of Wyman. PSNH's share of Wyman expenses is included in the corresponding operating expenses on the accompanying Statements of Income. F. DEPRECIATION The provision for depreciation is calculated using the straight-line method based on estimated remaining lives of depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agencies. Except for major facilities, depreciation rates are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.7 percent in 1997 and 1996, and 3.8 percent in 1995. See Note 5, "Nuclear Decommissioning," for information on nuclear plant decommissioning. PSNH's non-nuclear generating facilities have limited service lives. Plant may be retired in place or dismantled based upon expected future needs, the economics of the closure and environmental concerns. The costs of closure and removal are incremental costs and, for financial reporting purposes, are accrued over the life of the asset as part of depreciation. At December 31, 1997 and 1996, the accumulated provision for depreciation included approximately $34.2 million and $31.1 million, respectively, accrued for the cost of removal, net of salvage for nonnuclear generation property. G. REVENUES Other than revenues under fixed-rate agreements negotiated with certain wholesale, industrial and commercial customers and limited retail access programs, utility revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission. Regulatory commissions also have authority over the terms and conditions of nontraditional rate making arrangements. At the end of each accounting period, PSNH accrues an estimate for the amount of energy delivered but unbilled. For information on the PSNH rate proceeding and its impact on PSNH, see Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). H. REGULATORY ACCOUNTING AND ASSETS The accounting policies of PSNH and the accompanying financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered through future revenues. Through their actions, regulators also may reduce or eliminate the value of an asset, or create a liability. If any portion of PSNH's operations were no longer subject to the provisions of SFAS 71, as a result of a change in the cost-of-service based regulatory structure or the effects of competition, PSNH would be required to write off all of its related regulatory assets and liabilities unless there is a formal transition plan which provides for the recovery, through established rates, for the collection of approved stranded costs and to maintain the cost-of-service basis for the remaining regulated operations. At the time of transition, PSNH would be required to determine any impairment to the carrying costs of deregulated plant and inventory assets. Management anticipates that a restructuring program will be implemented within New Hampshire during the next few years. In a restructured environment, PSNH's generation business no longer will be rate regulated on a cost-of-service basis. The majority of PSNH's regulatory assets are related to its generation business. The staff of the SEC has had concerns regarding the appropriateness of the utilities' ability to continue application of SFAS 71 for the generation portion of their business in a restructured environment. The SEC referred the issue to the Emerging Issues Task Force (EITF) of the FASB which reached a consensus and issued "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101," (EITF 97-4). The EITF concluded: (1) the future recognition of regulatory assets for the portion of the business that no longer qualifies for application of SFAS 71 depends on the regulators' treatment of the recovery of those costs and other stranded assets from cash flows of other portions of the business still considered to be regulated, and (2) a utility should discontinue the application of SFAS 71 when a legislative and regulatory plan has been enacted, which would include transition plans into a competitive environment, and when the stranded costs which are subject to future rate recovery are determined. EITF 97-4 became effective in August 1997. The issue of restructuring the electric utility industry in New Hampshire is currently the focus of negotiations and proceedings within the federal and state court systems . Management believes that PSNH's use of regulatory accounting remains appropriate while this issue remains in litigation. PSNH expects that its transmission and distribution business will continue to be rate-regulated on a cost-of-service basis, and accordingly, will continue to apply SFAS 71 to this portion of its business. For more information on PSNH's regulatory environment and the potential impacts of rstructuring, see Note 11A, "Commitments and Contingencies - Restructuring and Rate Matters," and the MD&A. SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," requires the evaluation of long- lived assets, including regulatory assets, for impairment when certain events occur or when conditions exist that indicate the carrying amounts of assets may not be recoverable. SFAS 121 requires that any long-lived assets which are no longer probable of recovery through future revenues be revalued based on estimated future cash flows. If this revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. Management continues to believe that it is probable that PSNH will recover its investments in long-lived assets through future revenues. This conclusion may change in the future as the implementation of restructuring plans within the state of New Hampshire will generally require the formation of a separate generation entity which will be subject to competitive market conditions. As a result, PSNH will be required to assess the carrying amounts of its long-lived assets in accordance with SFAS 121. The components of PSNH's regulatory assets are as follows: At December 31, 1997 1996 (Thousands of Dollars) Recoverable energy costs, net (Note 2K) ................................. $191,686 $211,236 Income taxes, net (Note 2I)................... 128,244 151,431 Unrecovered contractual obligations (Note 5)........................ 83,042 50,271 Deferred costs, nuclear plants (Note 3)............................ 281,856 269,233 Seabrook deferral (Note 2K)................... 8,376 - Other......................................... 2,214 2,333 $695,418 $684,504 I. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the ratemaking treatment of the applicable regulatory commissions. See Note 10, "Income Tax Expense" for the components of income tax expense. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows: At December 31, 1997 1996 (Restated) (Restated) (Thousands of Dollars) Accelerated depreciation and other plant-related differences ........... $103,985 $225,263 Net operating loss (NOL) carryforwards ............................. (94,822) (94,149) Regulatory assets - income tax gross up .................................. 49,101 68,652 Other ....................................... 146,142 58,888 $204,406 $258,654 At December 31, 1997, PSNH had a NOL carryforward of approximately $293 million, that can be used against PSNH's federal taxable income and which, if unused, expires between the years 2000 and 2006. PSNH also had Investment Tax Credit (ITC) carryforwards of $40 million which if unused, expires between the years 1998 and 2004. For a portion of the carryforward amounts indicated above, the reorganization of PSNH under Chapter 11 of the United States Bankruptcy Code limits the annual amount of NOL and ITC carryforwards that may be used. Approximately $31 million of the NOL and $9 million of the ITC carryforwards are subject to this limitation. See Note 11A, "Commitments and Contingencies - Restructuring and Rate Matters," for the possible impacts on PSNH from the NHPUC's decision related to industry restructuring. J. UNAMORTIZED ACQUISITION COSTS The unamortized PSNH acquisition costs represent the aggregate value placed by the 1989 rate agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in excess of the net book value of PSNH's non-Seabrook assets, plus the $700 million value assigned to Seabrook by the Rate Agreement, as part of the bankruptcy resolution on June 5, 1992 (Acquisition Date). The Rate Agreement provides for the recovery through rates, with a return, of the unamortized PSNH acquisition costs. The Rate Agreement provides that $425 million of the unamortized PSNH acquisition costs be amortized over the first seven years after PSNH's May 16, 1991 reorganization from bankruptcy (Reorganization Date) with the remaining amount to be amortized over the 20-year period after the Reorganization Date. The unrecovered balance of PSNH acquisition costs at December 31, 1997, was approximately $402.3 million. In accordance with the Rate Agreement, approximately $32.9 million of this amount will be recovered through rates by June 1, 1998, and the remaining amount of approximately $369.4 million will be recovered through rates by 2011. As of December 31, 1997, PSNH has collected approximately $591 million of acquisition costs through rates. K. RECOVERABLE ENERGY COSTS Under the Energy Policy Act of 1992 (Energy Act), PSNH is assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (D&D assessment). The Energy Act requires that regulators treat D&D assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. PSNH is currently recovering these costs through rates. As of December 31, 1997, PSNH's total D&D deferrals were approximately $300 thousand. The Rate Agreement includes a comprehensive fuel and purchased power adjustment clause (FPPAC) permitting PSNH to pass through to retail customers, for a ten-year period that began in May 1991, the retail portion of differences between the fuel and purchased power costs assumed in the Rate Agreement and PSNH's actual costs, which include the costs related to the Seabrook Power Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are subject to a prudence review by the New Hampshire Public Utilities Commission (NHPUC). Under the Rate Agreement, charges made by NAEC through the Seabrook Power Contracts, including the deferred Seabrook capital expenses, are being deferred by PSNH and subsequently will be subsequently billed and collected by PSNH through the FPPAC. PSNH began to defer the amount of these costs on December 1, 1997 and will continue to do so for the period December 1, 1997 through May 31, 1998. Beginning on June 1, 1998, these costs will be recovered over a 36-month period. At December 31, 1997, PSNH has deferred approximately $8.4 million of these costs, which balance is recorded in PSNH's deferred costs, nuclear plants. On February 10, 1998, the NHPUC established a FPPAC rate for the period December 1, 1997 through May 31, 1998. The new FPPAC rate increased customer billings by approximately six percent. This rate continues to defer a substantial portion of these costs. At December 31, 1997, PSNH's net recoverable energy costs, excluding current net recoverable energy costs, were approximately $191.7 million. This amount includes approximately $172.9 million of deferred small power producer costs. See Note 11A, "Commitments and Contingencies - Restructuring and Rate Matters" for the possible impacts on PSNH of the NHPUC's decision related to industry restructuring. L. SPENT NUCLEAR FUEL DISPOSAL COSTS Under the Nuclear Waste Policy Act of 1982, PSNH must pay the United States Department of Energy (DOE) for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. Fees are billed currently to customers and paid to the DOE on a quarterly basis. The DOE was originally scheduled to begin accepting delivery of spent fuel in 1998. However, delays in identifying a permanent storage site have continually postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. The company has primary responsibility for the interim storage of its spent nuclear fuel. Current capability to store spent fuel at Seabrook are estimated to be adequate until the year 2010. Meeting spent fuel storage requirements beyond this period could require new and separate storage facilities, the costs for which have not been determined. Storage facilities for Millstone 3 are expected to be adequate for the projected life of the unit. In November 1997, the U.S. District Court of Appeals for the D.C. Circuit ruled that the lack of an interim storage facility does not excuse the DOE from meeting its contractual obligation to begin accepting spent nuclear fuel no later than January 31, 1998. Currently, the DOE has not taken the spent nuclear fuel as scheduled and, as a result, may have to pay contract damages. The ultimate outcome of this legal proceeding is uncertain at this time. M. CASH AND CASH EQUIVALENTS Cash and cash equivalents includes cash on hand and short-term cash investments which are highly liquid in nature and have original maturities of three months or less. 3. SEABROOK POWER CONTRACTS PSNH and NAEC have entered into two power contracts that obligate PSNH to purchase NAEC's 35.98 percent ownership of the capacity and output of Seabrook for the term of Seabrook's Nuclear Regulatory Commission (NRC) operating license. Under these power contracts, PSNH is obligated to pay NAEC's cost of service during this period, regardless of whether Seabrook 1 is operating. NAEC's cost of service includes all of its Seabrook-related costs, including operation and maintenance (O&M) expenses, fuel expense, income and property tax expense, depreciation expense, certain overhead and other costs and a return on its allowed investment. PSNH has included its right to buy power from NAEC on its Balance Sheets as part of utility plant and regulatory assets with a corresponding obligation. At December 31, 1997, this right was valued at approximately $917.1 million. The contracts established the value of the initial investment in Seabrook (initial investment) at $700 million. As prescribed by the Rate Agreement, as of May 1, 1996, NAEC phased into rates 100 percent of its investment in Seabrook 1. This plan is in compliance with SFAS 92,"Regulated Enterprises- Accounting for Phase-in Plans." From the Acquisition Date through November 1997, NAEC recorded $203.9 million of deferred return on its investment in Seabrook 1. At November 30, 1997, NAEC's utility plant included $84.1 million of deferred return that was transferred as part of the Seabrook plant assets to NAEC on the Acquisition Date. Beginning on December 1, 1997, the deferred return, including the portion transferred to NAEC, is currently being billed through the Seabrook Power Contracts to PSNH and will be fully recovered from customers by May 2001. NAEC depreciated its initial investment over the term of Seabrook 1's operating license (39 years), and any subsequent plant additions are depreciated on a straight- line basis over the remaining term of the power contracts at the time the subsequent additions are placed in service. If Seabrook 1 is shut down prior to the expiration of the NRC operating license, PSNH will be unconditionally required to pay NAEC termination costs for 39 years, less the period during which Seabrook 1 has operated. These termination costs will reimburse NAEC for its share of Seabrook 1 shut-down and decommissioning costs, and will pay NAEC a return of and on any undepreciated balance of its initial investment over the remaining term of the power contracts, and the return of and on any capital additions to the plant made after the Acquisition Date over a period of five years after shut down (net of any tax benefits to NAEC attributable the cancellation). Contract payments charged to operating expenses are approximately: Year Contract Payments (Thousands of Dollars) 1997................................. $188,000 1996................................. 159,000 1995................................. 154,000 Interest included in the contract payment was $57 million in 1997, $55 million in 1996, and $51 million in 1995. Future minimum payments, excluding executory costs, such as property taxes, state use taxes, insurance and maintenance, under the terms of the contracts, as of December 31, 1997, are approximately: Year Seabrook Power Contracts (Thousands of Dollars) 1998 ................................ $199,000 1999 ................................ 184,000 2000 ................................ 183,000 2001 ................................ 108,000 2002 ................................ 69,100 After 2002............................. 1,077,000 Future minimum payments................ 1,820,100 Less amount representing interest............................. 903,000 Present value of Seabrook Power Contracts payments .................. $ 917,100 See Note 11A, "Commitments and Contingencies - Restructuring and Rate Matters" for the possible impacts the NHPUC's restructuring decision may have on the Seabrook Power Contracts. 4. LEASES PSNH has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles and office space. The provisions of these lease agreements generally provide for renewal options. The following rental payments have been charged to expense: Year Capital Leases Operating Leases 1997............ $1,579,000 $5,657,000 1996............ 1,105,000 4,884,000 1995............ 1,103,000 5,291,000 Interest included in capital lease rental payments was $272,000 in 1997, $292,000 in 1996, and $351,000 in 1995. Future minimum rental payments, excluding executory costs, such as property taxes, state use taxes, insurance and maintenance, under long-term noncancellable leases, as of December 31, 1997, are: Year Capital Leases Operating Leases (Thousands of Dollars) 1998 ...................... $1,500 $ 6,100 1999 ...................... 1,200 5,300 2000 ...................... 1,000 4,700 2001 ...................... 1,000 4,200 2002 ...................... 100 2,200 After 2002 .................... 500 5,100 Future minimum lease payments .................... 5,300 $27,600 Less amount representing interest ..................... 600 Present value of future minimum lease payments ...... $4,700 5. NUCLEAR DECOMMISSIONING Millstone and Seabrook: Millstone 3 and Seabrook 1 have service lives that are expected to end during the years 2025 and 2026, respectively. Upon retirement, these units must be decommissioned. Current decommissioning studies concluded that complete and immediate dismantlement at retirement continues to be the most viable and economic method of decommissioning Millstone 3 and Seabrook 1. Decommissioning studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology and inflation. The estimated cost of decommissioning PSNH's 2.85 percent ownership share of Millstone 3 and NAEC's 35.98 percent share of Seabrook 1, in year-end 1997 dollars, is $15.6 million and $170.2 million, respectively. Millstone 3 and Seabrook 1 decommissioning costs will be increased annually by their respective escalation rates. PSNH's Millstone 3 decommissioning costs are accrued over the expected service life of the unit and are included in depreciation expense on its Statements of Income. Nuclear decommissioning costs related to PSNH's share of Millstone 3 amounted to $0.4 million in 1997 and 1996, and $0.3 million in 1995. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on PSNH's Balance Sheets. At December 31, 1997 and 1996, the balance in the accumulated reserve for depreciation amounted to $4.3 million and $3.2 million, respectively. PSNH makes payments to an independent decommissioning trust for its portion of the costs of decommissioning Millstone 3. NAEC's portion of the cost of decommissioning Seabrook 1 is paid to an independent decommissioning financing fund managed by the state of New Hampshire. Funding of the estimated decommissioning costs assumes levelized collections for Millstone 3 and escalated collections for Seabrook 1, and after-tax earnings on the Millstone and Seabrook decommissioning funds of approximately 5.5 percent and 6.5 percent, respectively. Under the terms of the Rate Agreement, PSNH is obligated to pay NAEC's share of Seabrook's decommissioning costs, even if the unit is shut down prior to the expiration of its operating license. Accordingly, NAEC bills PSNH directly for its share of the costs of decommissioning Seabrook 1. PSNH records its Seabrook decommissioning costs as a component of purchased power expense on its Statements of Income. Under the Rate Agreement, PSNH's Seabrook decommissioning costs are recovered through base rates. As of December 31, 1997, PSNH collected through rates approximately $2.6 million toward the future decommissioning costs of its share of Millstone 3, which has been transferred to the external decommissioning trust. As of December 31, 1997, NAEC has paid approximately $21.1 million (including payments made prior to the Acquisition Date by PSNH), into Seabrook 1's decommissioning financing fund. Earnings on the decommissioning trust and financing fund increase the decommissioning trust balance and the accumulated reserve for depreciation. Unrealized gains and losses associated with the decommissioning trust and financing fund also impact the balance of the trust, and the accumulated reserve for depreciation. Changes in requirements or technology, the timing of funding or dismantling, or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. PSNH attempts to recover sufficient amounts through its allowed rates to cover its expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by regulatory agencies is reflected in rates of PSNH. Based on present estimates and assuming its nuclear units operate to the end of their respective licensing periods, PSNH expects that the decommissioning trust and financing fund will be substantially funded when the units are retired from service. Yankee Companies: VYNPC owns and operates a nuclear generating unit with a service life that is expected to end in 2012. PSNH's ownership share of estimated costs, in year-end 1997 dollars, of decommissioning the unit owned and operated by VYNPC is $20.2 million. On August 6, 1997, the board of directors of MYAPC voted unanimously to cease permanently the production of power at its nuclear generating facility (MY). The NU system companies had relied on MY for approximately one percent of their capacity. During November 1997, MYAPC filed an amendment to its power contracts clarifying the obligations of its purchasing utilities following the decision to cease power production. During January 1998, the FERC accepted the amendments and proposed rates, subject to refund. At December 31, 1997, the remaining estimated obligation, including decommissioning, amounted to approximately $867.2 million, of which PSNH's share was approximately $43.4 million. On December 4, 1996, the board of directors of CYAPC voted unanimously to cease permanently the production of power at its nuclear generating plant (CY). During 1996, the NU system companies had relied on CY for approximately three percent of their capacity. During late December 1996, CYAPC filed an amendment to its power contracts clarifying the obligations of its purchasing utilities following the decision to cease power production. On February 27, 1997, the FERC approved an order for hearing which, among other things, accepted CYAPC's contract amendment. The new rates became effective March 1, 1997, subject to refund. At December 31, 1997, the remaining estimated obligation, including decommissioning, amounted to $619.9 million, of which PSNH's share was approximately $31.0 million. YAEC is in the process of decommissioning its nuclear facility. At December 31, 1997, the estimated remaining costs, including decommissioning, amounted to $124.4 million, of which PSNH's share was approximately $8.7 million. Under the terms of the contracts with MYAPC, CYAPC and YAEC, the shareholder-sponsor companies, including PSNH, are responsible for their proportionate share of the costs of the units, including decommissioning. Management expects that PSNH will continue to be allowed to recover these costs from its customers. Accordingly, PSNH has recognized these costs as regulatory assets, with corresponding obligations. Proposed Accounting: The staff of the SEC has questioned certain current accounting practices of the electric utility industry, including PSNH, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating units in the financial statements. In response to these questions, the FASB has agreed to review the accounting for closure and removal costs, including decommissioning. If current electric utility industry accounting practices for nuclear power plant decommissioning are changed, the annual provision for decommissioning could increase relative to 1997, and the estimated cost for decommissioning could be recorded as a liability (rather than as accumulated depreciation), with recognition of an increase in the cost of the related nuclear power plant. Management believes that PSNH will continue to be allowed to recover decommissioning costs through rates. 6. SHORT-TERM DEBT The amount of short-term borrowings that may be incurred by PSNH is subject to periodic approval by the SEC under the 1935 Act or by the NHPUC. Effective May 1997, PSNH was authorized under a waiver from the NHPUC, to incur short-term borrowings up to a maximum of $125 million. PSNH has a $125 million revolving credit agreement that will expire in April 1999. The revolving credit agreement is with a group of 16 banks. PSNH is obligated to pay a facility fee of .50 percent per annum on the commitment of $125 million. At December 31, 1997 and 1996, there were no borrowings under the facility. Under the credit facility discussed above, PSNH may borrow funds on a short-term revolving basis under its agreement, using either fixed-rate loans or standby loans. Fixed rates are set using competitive bidding. Standby loans are based upon several alternative variable rates. Money Pool: Certain subsidiaries of NU, including PSNH, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the system, and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate. However, borrowings based on loans from NU parent bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 1997 and 1996, PSNH had no outstanding borrowings from the Pool. Maturities of PSNH's short-term debt obligations are for periods of three months or less. For further information on short-term debt, see the MD&A. 7. EMPLOYEE BENEFITS A. PENSION BENEFITS The NU system subsidiaries participate in a uniform noncontributory defined benefit retirement plan covering all regular NU system employees. Benefits are based on years of service and employees' highest eligible compensation during 60 consecutive months of employment. PSNH's direct portion of the NU system's pension cost, part of which was charged to utility plant, approximated $1.3 million in 1997, $6.2 million in 1996, and $2.3 million in 1995. Pension (credits)/costs for 1997 and 1996 included approximately $(1.0) million and $1.9 million, respectively, related to workforce reduction programs. Currently, PSNH funds annually an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code. Pension costs are determined using market-related values of pension assets. Pension assets are invested primarily in domestic and international equity securities and bonds. The components of net pension cost for PSNH are: For the Years Ended December 31, 1997 1996 1995 (Thousands of Dollars) Service cost.......................... $ 2,987 $ 6,161 $ 3,462 Interest cost......................... 13,398 12,808 11,923 Return on plan assets................. (34,622) (24,393) (33,156) Net amortization...................... 19,508 11,608 20,108 Net pension cost...................... $ 1,271 $ 6,184 $ 2,337 For calculating pension cost, the following assumptions were used: For the Years Ended December 31, 1997 1996 1995 Discount rate.......................... 7.75% 7.50% 8.25% Expected long-term rate of return...... 9.25 8.75 8.50 Compensation/progression rate.......... 4.75 4.75 5.00 The following table represents the plan's funded status reconciled to the Balance Sheets: At December 31, 1997 1996 (Thousands of Dollars) Accumulated benefit obligation, including vested benefits at December 31, 1997 and 1996 of $(140,089,000) and $(131,624,000), respectively ........................... $(152,709) $(143,377) Projected benefit obligation ............. $(187,968) $(179,192) Market value of plan assets .............. 195,612 173,035 Market value in excess (less than) of projected benefit obligation ............. 7,644 (6,157) Unrecognized transition amount ............ 4,003 4,337 Unrecognized prior service costs .......... 7,597 8,135 Unrecognized net gain ..................... (65,305) (51,105) Accrued pension liability ................. $(46,061) $ (44,790) The following actuarial assumptions were used in calculating the plan's year-end funded status: For the Years Ended December 31, 1997 1996 Discount rate................................ 7.25% 7.75% Compensation/progression rate................ 4.25 4.75 B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS The NU system subsidiaries provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (referred to as SFAS 106 benefits). These benefits are available for employees retiring from the NU system who have met specified service requirements. For current employees and certain retirees, the total SFAS 106 benefit is limited to two times the 1993 per-retiree health care cost. The SFAS 106 obligation has been calculated based on this assumption. PSNH's direct portion of SFAS 106 benefits, part of which was deferred or charged to utility plant, approximated $4.9 million in 1997, $6.2 million in 1996, and $7.2 million in 1995. PSNH is funding SFAS 106 postretirement costs through external trusts. PSNH is funding, on an annual basis, amounts that have been rate- recovered and which also are tax-deductible under the Internal Revenue Code. The trust assets are invested primarily in equity securities and bonds. The components of health care and life insurance cost are: For the Years Ended December 31, 1997 1996 1995 (Thousands of Dollars) Service cost .................... $ 802 $ 914 $ 933 Interest cost ................... 3,352 3,559 4,063 Return on plan assets ........... (3,753) (1,720) (1,694) Amortization of unrecognized transition obligation ......... 2,941 2,941 2,941 Other amortization, net ......... 1,541 547 998 Net health care and life insurance cost ................ $4,883 $6,241 $7,241 For calculating PSNH's SFAS 106 benefit costs, the following assumptions were used: For the Years Ended December 31, 1997 1996 1995 Discount rate .................... 7.75% 7.50% 8.00% Long-term rate of return - Health assets, net of tax ..... 6.00 5.25 5.00 Life assets ................... 9.25 8.75 8.50 The following table represents the plan's funded status reconciled to the Balance Sheets: At December 31, 1997 1996 (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees ............................ $(36,790) $(38,245) Fully eligible active employees ......................... (31) (22) Active employees not eligible to retire ................ (9,788) (9,696) Total accumulated post- retirement benefit obligation ........................... (46,609) (47,963) Market value of plan assets ............ 22,908 17,882 Accumulated postretirement benefit obligation in excess of plan assets ................ (23,701) (30,081) Unrecognized transition amount ............................... 44,108 47,049 Unrecognized net gain .................. (20,407) (17,139) Accrued postretirement benefit liability ............................ $ - $ (171) The following actuarial assumptions were used in calculating the plan's year-end funded status: At December 31, 1997 1996 Discount rate ............................. 7.25% 7.75% Health care cost trend rate (a) ........... 5.76 7.23 (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 4.40 percent by 2001. The effect of increasing the assumed health care cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1997, by $3.1 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $245 thousand. The trust holding the health plan assets is subject to federal income taxes at a 39.6 percent tax rate. PSNH currently is recovering SFAS 106 costs through rates. 8. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock subject to mandatory redemption are: Shares Outstanding December 31, Description December 31, 1997 1997 1996 1995 (Thousands of Dollars) 10.60% Series A of 1991 .......... 4,000,000 $100,000 $125,000 $125,000 Less preferred stock to be redeemed within one year ......... 1,000,000 25,000 25,000 - Total preferred stock subject to mandatory redemption .... $ 75,000 $100,000 $125,000 In case of default on dividends or sinking-fund payments, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If PSNH is in arrears in the payment of dividends on any outstanding shares of preferred stock, PSNH would be prohibited from redemption or purchase of less than all of the preferred stock outstanding. The Series A Preferred Stock is not subject to optional redemption by PSNH. It is subject to an annual sinking fund requirement of $25 million, which began on June 30, 1997, sufficient to retire annually 1,000,000 shares at $25 per share. 9. LONG-TERM DEBT Details of long-term debt outstanding are: At December 31 1997 1996 (Thousands of Dollars) First Mortgage Bonds: 9.17% Series B, due 1998..................... $170,000 $170,000 Total First Mortgage Bonds............... 170,000 170,000 Pollution Control Revenue Bonds: 7.65% Tax-Exempt Series A, due 2021............ 66,000 66,000 7.50% Tax-Exempt Series B, due 2021............ 108,985 108,985 7.65% Tax-Exempt Series C, due 2021............ 112,500 112,500 Adjustable Rate, Taxable, Series D, due 2021 ....................................... 39,500 39,500 Adjustable Rate, Taxable, Series E, due 2021 ....................................... 69,700 69,700 Adjustable Rate, Tax-Exempt, Series D, due 2021 ....................................... 75,000 75,000 Adjustable Rate, Tax-Exempt, Series E due 2021 ....................................... 44,800 44,800 Less: Amounts due within one year ............... 170,000 - Long-term debt, net ....................... $516,485 $686,485 Long-term debt maturities and cash sinking-fund requirements on debt outstanding at December 31, 1997 aggregate approximately $170 million for 1998. There are neither sinking-fund requirements nor debt maturities existing for the years 1999 through 2002. Also, there are annual renewal and replacement fund requirements equal to 2.25 percent of the average of net depreciable utility property owned by PSNH at the Reorganization Date, plus cumulative gross property additions thereafter. PSNH expects to meet these future fund requirements by certifying property additions. Any deficiency would need to be satisfied by the deposit of cash or bonds. Essentially, all utility plant of PSNH is subject to the lien of its first mortgage bond indenture. PSNH's Revolving Credit Facility has a second lien, junior to the lien of its first mortgage bond indenture, on all PSNH property located in New Hampshire which will expire in April 1999. At December 31, 1997, there were no borrowings under the Revolving Credit Facility. Concurrent with the issuance of PSNH's Series A and B First Mortgage Bonds, PSNH entered into financing arrangements with the Business Finance Authority of the state of New Hampshire (BFA). Pursuant to these arrangements, the BFA issued seven series of Pollution Control Revenue Bonds (PCRBs) and loaned the proceeds to PSNH. At December 31, 1997, approximately $516.5 million of PCRBs were outstanding. The average effective interest rates on the variable-rate pollution control notes ranged from 3.8 percent to 5.6 percent for 1997, and from 3.5 percent to 5.5 percent for 1996. PSNH's obligation to repay each series of PCRBs is secured by a series of First Mortgage Bonds that were issued under its indenture. Each such series of First Mortgage Bonds contains terms and provisions with respect to maturity, principal payment, interest rate, and redemption that correspond to those of the applicable series of PCRBs. For financial reporting purposes, these bonds would not be considered outstanding unless PSNH fails to meet its obligations under the PCRBs. The PCRBs, except for Series D and E, are redeemable on or after May 1, 2001, at the option of the company with accrued interest and at specified premiums. Under current interest rate elections by PSNH, the Series D and E PCRBs are redeemable, at par plus accrued interest at the end of each interest-rate period. Future interest-rate elections by PSNH could significantly defer or eliminate the availability of optional redemptions by PSNH, and could affect costs as well. 10.INCOME TAX EXPENSE The components of the federal and state income tax provisions charged to operations are: For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) (Thousands of Dollars) Current income taxes: Federal ............................... $67,148 $(4,978) $(1,166) State ................................. 48 (1,605) 1,767 Total current ....................... 67,196 (6,583) 601 Deferred income taxes, net: Federal ............................... 20,983 95,225 72,147 State ................................. 1,202 306 (1,606) Total deferred ..................... 22,185 95,531 70,541 Investment tax credits, net ............. (540) (548) (555) Total income tax expense ................ $88,841 $88,400 $70,587 The components of total income tax expense are classified as follows: Income taxes charged to operating expenses ............................... $86,450 $80,677 $69,817 Other income taxes ...................... 2,391 7,723 770 Total income tax expense ................ $88,841 $88,400 $70,587 Deferred income taxes are comprised of the tax effects of temporary differences as follows: For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) (Thousands of Dollars) Depreciation ............................ $(1,937) $(1,055) $ 1,294 Deferred tax asset associated with NOL .............................. - 96,756 57,543 Energy adjustment clauses ............... 16,839 (10,716) 5,098 Amortization of regulatory settlement ............................ 11,501 11,501 11,501 Other ................................... (4,218) (955) (4,895) Deferred income taxes, net .............. $22,185 $95,531 $70,541 A reconciliation between income tax expense and the expected tax expense at the applicable statutory rate is as follows: For the Years Ended December 31, 1997 1996 1995 (Restated) (Restated) (Thousands of Dollars) Expected federal income tax at 35 percent of pretax income ........... $63,355 $64,931 $53,845 Tax effect of differences: Depreciation .......................... 1,890 1,896 1,868 Amortization of acquisition costs ..... 31,298 31,410 31,522 Seabrook intercompany loss ............ (4,616) (7,504) (13,048) Investment tax credit amortization .... (540) (548) (555) State income taxes, net of federal benefit ..................... 1,085 (845) 105 Other, net ............................ (3,631) (940) (3,150) Total income tax expense ................ $88,841 $88,400 $70,587 11. COMMITMENTS AND CONTINGENCIES A.RESTRUCTURING AND RATE MATTERS The 1996 restructuring legislation that the NHPUC is charged with implementing provides that the NHPUC may not adopt a restructuring plan that imposes a severe financial hardship on a utility. Management believes that PSNH is entitled to full recovery of its prudently incurred costs, including regulatory assets and other strandable costs. It bases this belief both on the general nature of public utility industry cost-of-service based regulation and the specific circumstances of the resolution of PSNH's previous bankruptcy proceedings and its acquisition by NU, including the recoveries provided by the Rate Agreement and related agreements. On February 28, 1997, the NHPUC issued its decision related to restructuring the state's electric utility industry and setting interim stranded cost charges for PSNH pursuant to legislation enacted in New Hampshire in 1996. In the decision, the NHPUC announced a departure from cost-based ratemaking and instead adopted a market-priced approach to ratemaking and stranded cost recovery. Accordingly, unless the NHPUC modifies its position or the litigation described below results in necessary modifications to the final plan which leads management to conclude that the ratemaking approach utilized in the NHPUC's restructuring decision will not go into effect, PSNH no longer will be subject to the provisions of SFAS 71. That would result in PSNH writing off from its balance sheet substantially all of its regulatory assets. The amount of the potential write-off triggered by the order is currently estimated at over $400 million, after taxes. PSNH does not believe that under the decision, it would be required to recognize any additional loss resulting from the impairment of the value of its other long-lived assets under the provisions of SFAS 121. On March 3, 1997, PSNH, NU, NAEC and NUSCO filed for a temporary restraining order, preliminary and permanent injunctive relief and for declaratory judgment in the United States District Court for New Hampshire (District Court). The case was subsequently transferred to Rhode Island. On March 10, 1997, the Chief Judge of the Rhode Island federal court issued a temporary restraining order which stayed the NHPUC's February 28, 1997 decision to the extent it established a rate- setting methodology that is not designed to recover PSNH's costs of providing service and would require PSNH to write off any regulatory assets. During 1997, a mediation process ended without a resolution. The District Court had suspended the procedural schedule associated with this court proceeding pending the resolution of appeals of certain preliminary rulings by the U.S. Circuit Court of Appeals for the First Circuit (First Circuit). On February 3, 1998, the First Circuit denied the appeals taken by would-be intervenors in PSNH's federal court proceeding concerning the NHPUC's final plan on restructuring. The First Circuit affirmed a previous court decision stating that the opposing interests in this case were adequately represented by the NHPUC or by PSNH. As a result of this decision, the proceedings in the District Court may resume. On February 17, 1998, the NHPUC filed a petition for rehearing with the First Circuit. The temporary restraining order issued by the District Court in March 1997 will remain in effect until further orders by either court. During 1997, the NHPUC reopened its proceeding to reconsider certain limited matters in its restructuring orders. The scope of the PSNH- specific rehearing proceedings included alternative rate-setting methodologies proposed by the intervenors; to decide the appropriate methodology to be used to determine PSNH's interim stranded costs; and to set PSNH's interim stranded cost charges utilizing the determined methodology. In testimony filed with the NHPUC in November 1997, PSNH proposed a new methodology to quantify its strandable costs. Under this proposal, PSNH would divest all owned generation and purchased-power obligations via auction. To the extent that the auction fails to produce sufficient revenues to cover the net book value of owned generation and contractual payment obligations of purchased-power, the difference would be recovered from customers through a non-bypassable distribution charge. The new proposal also relies upon securitization of certain assets to further reduce rates. On December 15, 1997, the NHPUC officially announced that industry restructuring would not take place on January 1, 1998. Management believes that industry restructuring will not take place in New Hampshire until the courts resolve the issues brought before them, or the parties involved reach a settlement. PSNH and NAEC are parties to a variety of financing agreements providing that the credit thereunder can be terminated or accelerated if they do not maintain specified minimum ratios of common equity to capitalization (as defined in each agreement). In addition, PSNH and NAEC are parties to a variety of financing agreements providing in effect that the credit thereunder can be terminated or accelerated if there are actions taken, either by PSNH or NAEC or by the state of New Hampshire, that deprive PSNH and/or NAEC of the benefits of the Rate Agreement and/or the Seabrook Power Contracts. If the NHPUC's February 28, 1997 decision were to become effective, it would, unless PSNH and NAEC receive waivers from their respective lenders, result in (i) write-offs that would cause PSNH's common equity to fall below the contractual minimums (ii) reductions in income that would cause PSNH's income to fall below the contractual minimums, (iii) potential violation of the contractual provisions with respect to actions depriving PSNH and NAEC of the benefits of the Rate Agreement and (iv) the potential for cross defaults to other PSNH and NAEC financing documents. Substantially all of PSNH's and NAEC's debt obligations would be affected. If these events transpired and if the creditors holding PSNH and NAEC debt obligations decide to exercise their rights to demand payment then either creditors or PSNH and NAEC could initiate proceedings under Chapter 11 of the bankruptcy laws. As a result of the NHPUC decision and the potential consequences discussed above, the reports of our auditors on the individual financial statements of PSNH and NAEC contain explanatory paragraphs. Those explanatory paragraphs indicate that a substantial doubt exists currently about the ability of PSNH and NAEC to continue as going concerns. The accounts of PSNH and NAEC are included in the consolidated financial statements of NU on the basis of a going concern. While the effect of the implementation of that decision would have a material adverse impact on NU's financial position, results of operations, and cash flows, it would not in and of itself result in defaults under borrowing or other financial agreements of NU or its other subsidiaries. On May 2, 1997, PSNH made a rate filing with the NHPUC. For information regarding this rate proceeding, see the MD&A. For information regarding the FERC rate proceedings for CYAPC and MYAPC, see Note 5, "Nuclear Decommissioning." B. NUCLEAR PERFORMANCE Millstone: The three Millstone units are managed by NNECO. Millstone 1, 2 and 3 have been out of service since November 4, 1995, February 21, 1996 and March 30, 1996, respectively, and are on the NRC's watch list. PSNH's ownership interest in the Millstone units is limited to a 2.85 percent joint ownership interest in Millstone 3. NU has restructured its nuclear organization and is currently implementing comprehensive plans to restart the units. Subsequent to its January 31, 1996 announcement that Millstone had been placed on its watch list, the NRC stated that the units cannot return to service until independent, third-party verification teams have reviewed the actions taken to improve the design, configuration and employee concerns issues that prompted the NRC to place the units on its watch list. The actual date of the return to service for each of the units is dependent upon the completion of independent inspections and reviews by the NRC and a vote by the NRC commissioners. NU hopes to return Millstone 3 to service in early spring of 1998 and Millstone 2 three to four months after Millstone 3. Millstone 1 is currently in extended maintenance status. Management cannot predict when the NRC will allow any of the Millstone units to return to service and thus cannot precisely estimate the total replacement power costs the NU system companies will ultimately incur. Replacement power costs incurred by NU attributable to the Millstone outages averaged approximately $28 million per month during 1997, and for 1998 are projected to average approximately $9 million per month for Millstone 3, $9 million per month for Millstone 2, and $6 million per month for Millstone 1 while the plants remain out of service. To date, PSNH's share of replacement power costs has not been material. PSNH's share of replacement power costs is not expected to be material for 1998, while Millstone 3 is out of service. CL&P, WMECO and PSNH will continue to expense their replacement power costs in 1998. Based on the current estimates of expenditures and restart dates, management believes the NU system has sufficient resources to fund the restoration of the Millstone units and related replacement power costs. If the return to service of Millstone 3 or 2 is delayed substantially beyond the present restart estimates, if some financing facilities become unavailable because of difficulties in meeting borrowing conditions or renegotiating extensions, if CL&P and WMECO encounter additional significant costs or if any other significant deviations from management's assumptions occur, CL&P and WMECO could be unable to meet their cash requirements. In those circumstances, management would take even more stringent actions to reduce costs and cash outflows and attempt to obtain additional sources of funds. The availability of these funds would be dependent upon general market conditions and CL&P's and WMECO's respective credit and financial conditions at that time. For information regarding Millstone restart costs, see the MD&A. Litigation: On August 7, 1997, the non-NU owners of Millstone 3 filed demands for arbitration with CL&P and WMECO as well as lawsuits in Massachusetts Superior Court against NU and its current and former trustees. The non-NU owners raise a number of contract, tort and statutory claims arising out of the operation of Millstone 3. The arbitrations and lawsuits seek to recover compensatory damages, punitive damages, treble damages and attorneys' fees. Owners representing approximately two-thirds of the non-NU interests in Millstone 3 claimed compensatory damages in excess of $200 million. In addition, one of the lawsuits seeks to restrain NU from disposing of its shares of the stock of WMECO and HWP, pending the outcome of the lawsuit. Management cannot estimate the potential outcome of these suits but believes there is no legal basis for the claims and intends to defend against them vigorously. To date, no reserves have been established for this litigation. At December 31, 1997, the costs related to this litigation for the NU system were estimated to be $100 million for incremental O&M costs and approximately $100 million for replacement power costs. These costs are likely to increase as long as Millstone 3 remains out of service. C. ENVIRONMENTAL MATTERS The NU system is subject to regulation by federal, state and local authorities with respect to air and water quality, the handling and disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. The NU system has an active environmental auditing and training program and believes that it is in substantial compliance with current environmental laws and regulations. However, the NU system is subject to certain pending enforcement actions and governmental investigations in the environmental area. Management cannot predict the outcome of these enforcement actions and investigations. Environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations and other facilities. Changing environmental requirements could also require extensive and costly modifications to PSNH's existing generating units, and transmission and distribution systems, and could raise operating costs significantly. As a result, PSNH may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation and transmission of electricity and the storage, transportation and disposal of by-products and wastes. PSNH may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. The cumulative long-term cost impact of increasingly stringent environmental requirements cannot be estimated accurately. PSNH has recorded a liability based upon currently available information for what it believes are its estimated environmental remediation costs that it expects to incur for waste disposal sites. In most cases, additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation and the possible effects of technological changes. At December 31, 1997, the net liability recorded by PSNH for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $5.6 million, which management has determined to be the most probable amount. During 1997, PSNH adopted Statement of Position 96-1, "Environmental Remediation Liabilities" (SOP). The principal objective of the SOP is to improve the manner in which existing authoritative accounting literature is applied by entities to specific situations of recognizing, measuring and disclosing environmental remediation liabilities. The adoption of the SOP resulted in an increase of approximately $400 thousand to PSNH's environmental reserve in 1997. PSNH cannot estimate the potential liability for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws, and regulatory practices, management does not believe the matters disclosed above will have a material effect on PSNH's financial position or future results of operations. D. NUCLEAR INSURANCE CONTINGENCIES Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities in the country covered by the federal government's third-party liability indemnification program, an owner of a nuclear unit could be assessed in proportion to its ownership interest in each of its nuclear units up to $75.5 million. Payments of this assessment would be limited to $10.0 million in any one year per nuclear incident based upon the owner's pro rata ownership interest in each of its nuclear units. In addition, the owner would be subject to an additional five percent or $3.8 million, in proportion to its ownership interests in each of its nuclear units, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection. Under the terms of the Seabrook Power Contracts with NAEC, PSNH could be obligated to pay for any assessment charged to NAEC as a "cost of service." Based on its ownership interest in Millstone 3 and NAEC's ownership interest in Seabrook 1, PSNH's maximum liability, including any additional assessments, would be $30.8 million per incident of which payments would be limited to $3.9 million per year. In addition, through power purchase contracts with MYAPC, VYNPC and CYAPC, PSNH would be responsible for up to an additional $11.1 million per incident, of which payments would be limited to a maximum of $1.4 million per year. Insurance has been purchased to cover the primary cost of repair, replacement or decontamination of utility property resulting from insured occurrences at Millstone 3 and CY. PSNH is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessment against PSNH with respect to losses arising during the current policy year is approximately $0.4 million under the primary property insurance program. Insurance has been purchased to cover certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences. PSNH is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessments against PSNH (including costs resulting from PSNH's contracts with NAEC), with respect to losses arising during current policy years are approximately $2.2 million under the replacement power policies and $5.2 million under the excess property damage, decontamination and decommissioning policies. Although PSNH has purchased the limits of coverage currently available from the conventional nuclear insurance pools, the cost of a nuclear incident could exceed available insurance proceeds. Insurance has been purchased aggregating $200 million on an industry basis for coverage of worker claims. All participating reactor operators insured under this coverage are subject to retrospective assessments of $3 million per reactor. The maximum potential assessment against PSNH (including costs resulting from the Seabrook Power Contracts with NAEC), with respect to losses arising during the current policy period is approximately $1.8 million. Effective January 1, 1998, a new worker policy was purchased which is not subject to retrospective assessments. E. CONSTRUCTION PROGRAM The construction program is subject to periodic review and revision by management. PSNH currently forecasts construction expenditures of approximately $302.6 million for the years 1998-2002, including approximately $41.9 million for 1998. In addition, PSNH estimates that nuclear fuel requirements, for its share of Millstone 3, will be $5.1 million for the years 1998-2002, including $1.7 million for 1998. F. LONG-TERM CONTRACTUAL ARRANGEMENTS Yankee Companies: PSNH, CL&P and WMECO rely on VY for approximately 1.7 percent of their capacity under long-term contracts. Under the terms of their agreements, the NU system companies pay their ownership (or entitlement) shares of costs, which include depreciation, O&M expenses, taxes, the estimated cost of decommissioning and a return on invested capital. These costs are recorded as purchased power expense and are recovered through the companies' rates. PSNH's total cost of purchases under contracts with VYNPC, amounted to $6.2 million in 1997, $6.5 million in 1996 and 1995. The other Yankee generating facilities, MY, CY and Yankee Rowe, were permanently shutdown as of August 6, 1997, December 4, 1996, and February 26, 1992, respectively. See Note 2E, "Summary of Significant Accounting Policies-Investments and Jointly Owned Electric Utility Plant," for more information on the Yankee companies. See Note 5, "Nuclear Decommissioning," regarding information on the related decommissioning studies. Nonutility Generators (NUGs): PSNH has requirements under various arrangements for the purchase of capacity and energy from NUGs. These arrangements have terms from 20 to 30 years, currently expiring in the years 1998 through 2023, and require PSNH to purchase energy at specified prices or formula rates. For the 12 months ending December 31, 1997, approximately 14 percent of the NU system electricity requirements were met by NUGs. PSNH's total cost of purchases under these arrangements amounted to $133.1 million in 1997, $132.6 million in 1996, and $124.0 million in 1995. These costs may be deferred for eventual recovery through rates. For additional information, see Note 2K, "Summary of Significant Accounting Policies-Recoverable Energy Costs." New Hampshire Electric Cooperative: PSNH entered into a buy-back agreement to purchase the capacity and energy of the New Hampshire Electric Cooperative, Inc.'s (NHEC) share of Seabrook 1 and to pay all of NHEC's Seabrook 1 costs for a ten-year period, which began on July 1, 1990. The total cost of purchases under this agreement was $23.4 million in 1997, $14.6 million in 1996, and $15.8 million in 1995. The total cost of these purchases has been collected through the FPPAC in accordance with the Rate Agreement. In connection with the agreement, NHEC agreed to continue as a firm-requirements customer of PSNH for 15 years. Hydro-Quebec: Along with other New England utilities, PSNH, CL&P, WMECO, and HWP have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. PSNH is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M and capital costs of these facilities. Estimated Annual Costs: The estimated annual costs of PSNH's significant long-term contractual arrangements are as follows: 1998 1999 2000 2001 2002 (Millions of Dollars) VYNPC ................... $ 7.1 $ 7.1 $ 6.7 $ 7.4 $ 7.7 NUGs .................... 139.4 142.9 147.1 151.3 155.5 NHEC .................... 30.0 30.0 14.6 - - Hydro-Quebec ............ 10.2 9.8 9.7 9.4 9.2 For additional information regarding the recovery of purchased power costs, see Note 2K, "Summary of Significant Accounting Policies - Recoverable Energy Costs." G. DEFERRED RECEIVABLE FROM AFFILIATED COMPANY At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance with the phase-in under the Rate Agreement, it began accruing a deferred return on a portion of its Seabrook investment. From May 16, 1991 to the Acquisition Date, PSNH accrued a deferred return of $50.9 million. On the Acquisition Date, PSNH sold the $50.9 million deferred return to NAEC as part of the Seabrook-related assets. At the time PSNH transferred the deferred return to NAEC, it realized, for income tax purposes, a gain that is deferred under the consolidated income tax rules. Beginning December 1, 1997, this gain is being restored for income tax purposes, as the deferred return of $50.9 million, and the associated income taxes of $32.9 million, are being collected by NAEC through the Seabrook Power Contracts. As NAEC recovers the $32.9 million in years eight through ten of the Rate Agreement, it will be obligated to make these corresponding payments to PSNH. On the Acquisition Date, PSNH recorded the $32.9 million of income taxes associated with the deferred return as a deferred receivable from NAEC, with a corresponding entry to deferred revenue, on its Balance Sheet. In 1993, due to changes in tax rates, this amount was adjusted to $33.2 million. For further information related to the phase-in of the Seabrook power plant, see Note 3, "Seabrook Power Contracts." See Note 11A, "Commitments and Contingencies - Restructuring and Rate Matters" for the possible impacts of the NHPUC's decision related to industry restructuring on this intercompany transaction between PSNH and NAEC. 12.FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and nuclear decommissioning trusts: The carrying amounts approximate fair value. SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," requires investments in debt and equity securities to be presented at fair value. Unrealized gains and losses resulting from the use of SFAS 115 accounting have not been material. Preferred stock and long-term debt: The fair value of PSNH's fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of PSNH's financial instruments and the estimated fair values are as follows: Carrying Fair At December 31, 1997 Amount Value (Thousands of Dollars) Preferred stock subject to mandatory redemption........................ $100,000 $ 99,000 Long-term debt - First Mortgage Bonds......... 170,000 170,425 Other long-term debt.......................... 516,485 537,599 Carrying Fair At December 31, 1996 Amount Value (Thousands of Dollars) Preferred stock subject to mandatory redemption........................ $125,000 $125,000 Long-term debt - First Mortgage Bonds......... 170,000 175,729 Other long-term debt.......................... 516,485 523,536 The fair values shown above have been reported to meet the disclosure requirements and do not purport to represent the amounts at which those obligations would be settled. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Public Service Company of New Hampshire: We have audited the accompanying balance sheets, as restated - see Note 1, of Public Service Company of New Hampshire (a New Hampshire corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31, 1997 and 1996, and the related statements of income, common stockholder's equity, and cash flows, as restated - see Note 1, for each of the three years in the period ended December 31, 1997. 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 Public Service Company of New Hampshire as of December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. The accompanying financial statements have been prepared assuming that the company will continue as a going concern. As discussed in Note 11A, on February 28, 1997, the State of New Hampshire Public Utilities Commission (the NHPUC) issued an order outlining its final plan to restructure the electric utility industry. The final plan announced a departure from cost- based rate making, which, if implemented, would require the company to discontinue the application of Financial Accounting Standard No. 71, "Accounting for the Effects of Certain Types of Regulation," (FAS 71). The implementation of the final plan, including the effect of the discontinuation of FAS 71, would result in after tax write-off of over $400 million. Such a write-off would cause the company to be in technical default under financial covenants imposed by lenders, which, would, if not waived or renegotiated, give rise to the rights of lenders to accelerate the repayment of approximately $686 million of the company's indebtedness and approximately $495 million of an affiliated company's indebtedness. These conditions raise substantial doubt about the company's ability to continue as a going concern. The financial statements referred to above do not include any adjustments that might result from the outcome of this uncertainty. As explained in Note 1 to the consolidated financial statements, the company has given retroactive effect to the change in accounting for nuclear compliance costs. /s/ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 20, 1998 (except with respect to the matter discussed in Note 1, as to which the date is June 10, 1998) PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE Management's Discussion and Analysis of Financial Condition and Results of Operations This section contains management's assessment of Public Service Company of New Hampshire's (PSNH or the company) financial condition and the principal factors having an impact on the results of operations. The company is a wholly-owned subsidiary of Northeast Utilities (NU). This discussion should be read in conjunction with the company's financial statements and footnotes. FINANCIAL CONDITION OVERVIEW Net income was approximately $92 million for 1997 compared to approximately $97 million for 1996. The decrease in net income was primarily due to higher operation expenses. Retail kilowatt-hour sales were essentially unchanged in 1997. A significant issue facing PSNH in 1998 is the industry restructuring efforts in New Hampshire. A temporary restraining order issued by a U.S. District Court is currently blocking the New Hampshire Public Utilities Commission (NHPUC) from implementing a February 1997 restructuring order that would have resulted in a write-off by PSNH of more than $400 million. Management hopes to negotiate an alternative restructuring proposal in 1998 that will produce significant PSNH rate reductions and allow retail customers to choose their electric suppliers, but still give PSNH and North Atlantic Energy Corporation (NAEC) an opportunity to maintain an adequate financial condition and earn fair returns on their investments. RESTRUCTURING In February, 1997, the NHPUC issued orders to restructure the state's electric utility industry and set interim stranded cost charges for PSNH. In the orders, the NHPUC announced a departure from cost-based ratemaking and adopted a market- priced approach to stranded cost recovery. PSNH, NU, NAEC and Northeast Utilities Service Company (NUSCO) filed for a temporary restraining order, preliminary and permanent injunctive relief and a declaratory judgment in the United States District Court of New Hampshire. The case subsequently was transferred to the United States District Court of Rhode Island (District Court) where a temporary restraining order was granted, staying, indefinitely, the enforcement of the NHPUC's restructuring orders as they affected PSNH. Certain appeals to the preliminary ruling have been denied and proceedings in the District Court are expected to resume. The NHPUC conducted rehearing proceedings in 1997 to decide the appropriate methodology to be used to determine PSNH's interim stranded costs and to set PSNH's interim stranded cost charges utilizing the determined methodology. The NHPUC has not indicated when it will issue a decision in these proceedings. On December 15, 1997, the NHPUC officially announced that industry restructuring would not take place on January 1, 1998. On December 24, 1997, the Governor's office filed a motion with the NHPUC formally requesting that certain issues concerning the rate agreement (Rate Agreement) between NU, PSNH and the state of New Hampshire, entered into in 1989 in connection with NU's reorganization plan to resolve PSNH's bankruptcy, be transferred to the New Hampshire Supreme Court for decision. The motion recommends that the NHPUC not issue any new rulings concerning the Rate Agreement pending such Supreme Court decision. On February 20, 1998, the NHPUC petitioned the New Hampshire Supreme Court to review two issues regarding the Rate Agreement; (i) whether the Rate Agreement creates private rights which would allow PSNH to seek damages under a contract theory if PSNH receives less than the full amount it claims as strandable costs under the Rate Agreement, and (ii) if yes, against whom and under what conditions such rights be enforceable. The Supreme Court first must determine whether it will accept the NHPUC's petition. As part of the rehearing proceedings, PSNH proposed a new methodology to quantify its stranded costs. Under this proposal, PSNH would divest its owned generation and purchased power obligations via auction. To the extent that the auction fails to produce sufficient revenues to cover the net book value of owned generation and contractual payment obligations of purchased power, the difference would be recovered from customers through a non-bypassable distribution charge. The new proposal also relies upon securitization of certain assets to further reduce rates. On February 20, 1998, PSNH forwarded a settlement offer to representatives from the state of New Hampshire that was consistent with PSNH's proposal in the rehearing proceedings, including among other things, a 20 percent rate reduction at the beginning of 1999, an auction of PSNH's non-nuclear generating units and securitization of approximately $1.15 billion of PSNH's stranded costs. See the "Notes to Financial Statements," Note 11A, for the potential accounting impacts of restructuring. RATE MATTERS PSNH's Rate Agreement provided for seven base rate increases and a comprehensive fuel and purchased power adjustment clause (FPPAC). In June 1996, the final base rate increase of 5.5 percent went into effect. Although the FPPAC continues for an additional four years beyond the end of the fixed rate period, there is uncertainty regarding how it will continue to function. The costs associated with purchases by PSNH from certain non-utility generators (NUGs) at prices above the level assumed in rates are deferred and recovered through the FPPAC. At December 31, 1997, NUG deferrals totaled approximately $173 million. On May 2, 1997, PSNH made a rate filing with the NHPUC requesting base rates to remain at their current level after May 31, 1997. By order dated November 6, 1997, the NHPUC ordered a temporary rate reduction for PSNH at a revenue level 6.87 percent lower than current rates. The NHPUC also set an interim return on equity of 11 percent. The temporary rates became effective December 1, 1997. A final decision, which will be reconciled to July 1, 1997, is not expected to be issued until September, 1998. A portion of this reduction was offset by an increase to rates through the FPPAC. On February 10, 1998, the NHPUC ordered an FPPAC rate for the period December 1, 1997 through May 31, 1998, which increased customer bills by approximately 6 percent. Prior to this increase, the FPPAC rate had been a credit to reflect a customer refund ordered by the NHPUC beginning in June 1996. This rate continues to defer recovery of a substantial portion of costs for the future. In addition, recovery of the Seabrook deferred return (approximately $127 million annually) is scheduled to begin in June 1998. On March 19, 1998, PSNH filed a proposed change to its rates, effective June 1, 1998. Public hearings are scheduled to take place in May 1998. The NHPUC also confirmed in its February 10, 1998 decision that it would disallow approximately $3 million in replacement power costs related to outages at Connecticut Yankee, Maine Yankee and Vermont Yankee and require PSNH to set aside $10 million as a reserve for potential overpayments due to the fact that PSNH has not required small power producers to reduce deliveries during so- called "light-loading" periods, pending the NHPUC's review of this matter. The decision also alleges various breaches of the Rate Agreement and ordered PSNH to meet with the State to discuss these matters. Finally, the decision indicated that the NHPUC would open a proceeding to review whether the proceeds from the sale of steam generators (approximately $20.9 million for NAEC's share) related to the canceled Unit II at Seabrook station should flow through rates to reduce customer bills. See the "Notes to Financial Statements," Note 2K, for further information on the FPPAC. LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations decreased approximately $44 million in 1997, compared to 1996, primarily due to lower recoveries through the FPPAC as a result of a customer refund ordered by the NHPUC and higher costs due to the Seabrook outage that are not being recovered currently, partially offset by higher working capital. Cash used for financing activities decreased approximately $116 million in 1997, compared to 1996, due primarily to the repayment of long-term debt in 1996, partially offset by the higher payment of cash dividends on common stock and the repayment of preferred stock in 1997. Cash used for investments decreased approximately $21 million in 1997, compared to 1996, primarily due to a decrease in investments in the NU system Money Pool. PSNH has a $125 million revolving credit agreement that will expire in April 1999. At December 31, 1997 there were no borrowings under the facility. PSNH has a first mortgage bond maturity of $170 million, plus accrued interest, on May 14, 1998. PSNH expects to meet that maturity with cash on hand and borrowing under the revolving credit agreement. Each major subsidiary of NU finances its own needs. Neither CL&P nor WMECO has any financing agreements containing cross defaults based on financial defaults by NU, PSNH or NAEC. Similarly, neither PSNH nor NAEC has any financing agreements containing cross defaults based on financial defaults by NU, CL&P or WMECO. Nevertheless, it is possible that investors will take negative operating results or regulatory developments at one company in the NU system into account when evaluating other companies in the NU system. That could, as a practical matter and despite the contractual and legal separations among the NU companies, negatively affect each company's access to financial markets. NUCLEAR PERFORMANCE MILLSTONE 3 PSNH has a 2.85 percent joint ownership interest in Millstone 3. Millstone 3 has been out of service since March 30, 1996. Subsequent to its January 31, 1996, announcement that Millstone had been placed on its watch list, the NRC has stated that the unit cannot return to service until independent, third party verification teams have reviewed the actions taken to improve the design, configuration and employee concerns issues that prompted the NRC to place the unit on its watch list. The actual date of the return to service for the unit is dependent upon the completion of independent inspections, reviews by the NRC and a vote by the NRC commissioners. In January 1998, NU declared Millstone 3 physically ready for restart, which meant that almost all of the restart-required physical work had been completed in the plant. The NRC currently is conducting a series of inspections to determine, among other things, whether the plant has effective leadership and corrective action and employee concerns programs. The Independent Corrective Action Verification Program, an NRC-ordered independent review of the plant's design and licensing bases, is expected to be completed in March 1998. To date, PSNH's costs related to the Millstone 3 outage have not had a material impact on the company's financial position or results of operations. Management expects that, under its current planning assumptions, Millstone 3's outage- related costs will continue to be immaterial to the company's results of operations. SEABROOK PSNH is obligated to purchase North Atlantic Energy Corporation's (NAEC) 35.98- percent share of the capacity and output generated by Seabrook 1(Seabrook) under the Seabrook Power Contract for a period equal to the length of the NRC full- power operating license for Seabrook (through 2026) whether or not Seabrook is operating and without regard to the cost of alternative sources of power. North Atlantic Energy Service Corporation is the managing agent and operates Seabrook. Seabrook operated at a capacity factor of 78.3 percent through December 1997, compared to 96.8 percent for the same period in 1996. The lower 1997 capacity factor is due primarily to the 50-day scheduled refueling and maintenance outage which began on May 10, 1997, and an unplanned outage that began on December 5, 1997. The unplanned outage occurred when the unit was shut down to repair leaks in a three inch stainless steel pipe in the residual heat removal system. The pipe was replaced, but problems were subsequently discovered in the control building air conditioning system. Design changes were implemented and the plant returned to service on January 16, 1998. DECOMMISSIONING CONNECTICUT YANKEE PSNH has a 5 percent ownership interest in the Connecticut Yankee nuclear generating facility (CY or the plant). On December 4, 1996, the Board of Directors of Connecticut Yankee Atomic Power Company voted unanimously to cease permanently the production of power at the plant. The decision to retire CY from commercial operation was based on an economic analysis of the costs of operating it compared to the costs of closing it and incurring replacement power costs over the remaining period of the plant's operating license, which would have expired in 2007. The economic analysis showed that closing the plant and incurring replacement power costs produced substantial savings. CY has undertaken a number of regulatory filings intended to implement the decommissioning. In late December 1996, CY filed an amendment to its power contracts with the FERC to clarify the obligations of its purchasing utilities following the decision to cease power production. At December 31, 1997, PSNH's share of these obligations was approximately $31 million, including the cost of decommissioning and the recovery of existing assets. Management expects that PSNH will continue to be allowed to recover such FERC approved costs from their customers. Accordingly, PSNH has recognized its share of the estimated costs as a regulatory asset, with a corresponding obligation, on its balance sheets. MAINE YANKEE PSNH has a 5 percent ownership interest in the Maine Yankee (MY) nuclear generating facility. On August 6, 1997, the Board of Directors of Maine Yankee Atomic Power Company (MYAPC) voted unanimously to retire MY. On January 14, 1998, FERC released a draft order on the MYAPC application to amend its power contracts with the owner/purchasers and revise its decommissioning and other charges. FERC has accepted the proposed application for filing and made the amendments and the proposed charges under the contracts effective on January 15, 1998, subject to refund after hearings. At December 31, 1997, PSNH's share of the estimated remaining obligation, including decommissioning amounted to approximately $43 million. Under the terms of the contracts with MYAPC, the shareholders' sponsor companies, including PSNH, are responsible for their proportionate share of the costs of the unit, including decommissioning. Management expects that PSNH will be allowed to recover these costs from its customers. Accordingly, PSNH has recognized these costs as a regulatory asset, with a corresponding obligation on its balance sheet. MILLSTONE AND SEABROOK PSNH's estimated cost to decommission its 2.85 percent share of Millstone 3 and NAEC's 35.98 share of Seabrook is approximately $16 million and $170 million, respectively, in year end 1997 dollars. These costs are being recognized over the lives of the respective units with a portion currently being recovered through rates. Under the terms of the Rate Agreement, the company is obligated to pay NAEC's share of Seabrook's decommissioning costs, even if the unit is shut down prior to the expiration of its operating license. As of December 31, 1997, the market value of the contributions already made to the Millstone 3 and Seabrook decommissioning trusts, including their investment returns, was approximately $4 million and $26 million, respectively. See the "Notes to Financial Statements," Note 5, for further information on nuclear decommissioning, including PSNH's share of costs to decommission the other regional nuclear generating units. ENVIRONMENTAL MATTERS PSNH is potentially liable for environmental cleanup costs at a number of sites inside and outside its service territory. To date, the future estimated environmental remediation liability has not been material with respect to the earnings or financial position of PSNH. At December 31, 1997, PSNH had recorded an environmental reserve of approximately $5.6 million. See the "Notes to Financial Statements" Note 11C, for further information on environmental matters. YEAR 2000 ISSUE The Year 2000 issue exists because many computer systems and applications currently use two-digit date fields to designate a year. As the change of the century occurs, date-sensitive systems may recognize the year 2000 as 1900, or not recognize it at all. This inability to recognize or properly treat the year 2000 may cause NU systems to process critical financial and operational information incorrectly. The company has assessed and continues to assess the impact of the Year 2000 issue on its operating and reporting systems. The assessment of the nuclear operating systems is continuing and is expected to be completed in the summer of 1998. The NU system will utilize both internal and external resources to reprogram or replace, and test the software for Year 2000 modifications. The total estimated remaining cost of the Year 2000 project is $37 million and is being funded through operating cash flows. This estimate does not include any costs for the replacement or repair of equipment or devices that may be identified during the assessment process. The majority of these costs will be expensed as incurred over the next two years. To date, the NU system has incurred and expensed approximately $4 million related to the assessment of, and preliminary efforts in connection with, its Year 2000 project. The costs of the project and the date on which the company plans to complete the Year 2000 modifications are based on management's best estimates, which were derived utilizing numerous assumptions of future events including the continued availability of certain resources, third party modification plans and other factors. However, there can be no guarantee that these estimates will be achieved, and actual results could differ materially from those plans. If the NU system's remediation plan is not successful, there could be a significant disruption of the NU system's operations. RESULTS OF OPERATIONS Income Statement Variances Increase/(Decrease) Millions of Dollars 1997 over/(under) 1996 1996 over/(under) 1995 Amount Percent Amount Percent Operating revenues $(2) - % $130 13% Fuel, purchased and net interchange power (30) (8) 100 39 Other operation 42 13 13 4 Maintenance (7) (16) 3 8 Other, net (7) (92) 5 (a) Interest on long-term debt (6) (11) (19) (25) Other interest expense (3) (91) 3 (a) Net income (5) (5) 14 17 (a) Percent greater than 100 OPERATING REVENUES Total operating revenues decreased in 1997 primarily due to lower fuel recoveries, partially offset by higher retail revenues. Fuel recoveries decreased approximately $12 million, primarily due to the customer refund ordered by the NHPUC. Retail revenues increased approximately $9 million, primarily due to the June 1996 rate increase, partially offset by the December 1997 rate decrease and higher price discounts to retain customers. Retail sales were essentially unchanged. Total operating revenues increased in 1996, primarily due to higher fuel recoveries, regulatory decisions, and other retail revenues. Fuel recoveries increased $112 million, primarily due to revenues resulting from the intercompany allocation of energy costs to NU affiliated companies ($125 million) and higher base fuel revenues primarily as a result of the June 1996 and 1995 retail-rate increases, partially offset by lower FPPAC revenues as a result of a customer refund ordered by the NHPUC. Revenues related to regulatory decisions increased $8 million, primarily due to the retail-rate increases. Other retail revenues increased $10 million primarily due to sales growth and other revenue sources. Retail sales increased 0.4 percent ($2 million), primarily due to economic growth in 1996, partially offset by milder weather in 1996. FUEL EXPENSE Fuel, purchased and net interchange power expense decreased in 1997, primarily due to the timing in the recognition of fuel expenses under the FPPAC, partially offset by higher purchased power costs. Fuel, purchased and net interchange power expense increased in 1996, primarily due to higher purchased power costs and the timing in the recognition of fuel expenses under the FPPAC. OTHER OPERATION AND MAINTENANCE EXPENSE Other operation and maintenance expense increased in 1997 primarily due to higher capacity charges under the Seabrook Power Contract as a result of the scheduled May 1997 refueling and maintenance outage and the unplanned December 1997 outage ($23 million), higher capacity purchases from NHEC ($11 million), higher capacity charges from MY ($4 million) and higher costs for PSNH's share of Millstone 3 ($3 million), partially offset by lower fossil costs ($4 million) and lower administration and sales costs ($3 million). Other operation and maintenance expenses increased in 1996, primarily due to higher storm costs, higher employee benefit costs, higher capacity charges under the Seabrook Power Contracts and higher marketing costs. OTHER, NET Other, net decreased in 1997 and increased in 1996, primarily due to the deferral in 1996 of interest expense ($5 million) associated with the FPPAC refund. INTEREST ON LONG-TERM DEBT Interest on long-term debt decreased in 1997 and 1996, primarily due to the repayment of the $172.5 million Series A first-mortgage bond in May 1996. OTHER INTEREST EXPENSE Other interest expense decreased in 1997 and increased in 1996, primarily due to 1996 interest expense ($5 million) associated with the FPPAC refund. SELECTED FINANCIAL DATA (a) For the Years Ended Dec.31, 1997 Dec. 31, 1996 Dec. 31, 1995 (Restated) (Restated) (Thousands of Dollars) Operating Revenues... $1,108,459 $1,110,169 $ 979,971 Operating Income..... 144,024 155,758 155,628 Net Income .......... 92,172 97,465 83,255 Cash Dividends on Common Stock....... 85,000 52,000 52,000 At Dec.31, 1997 Dec. 31, 1996 Dec. 31, 1995 Total Assets......... $2,837,159 $2,851,212 $2,920,487 Long-Term Debt (b)... 686,485 686,485 858,985 Preferred Stock Subject to Mandatory Redemption(b)...... 100,000 125,000 125,000 Obligations Under Seabrook Power Contracts and Other Capital Leases(b).. 921,813 914,617 915,288 (a) Reclassifications of prior data have been made to conform with the current presentation. (b) Includes portions due within one year. Dec. 31, 1994 Dec. 31, 1993 (Thousands of Dollars) $922,039 $864,415 152,086 124,710 77,444 52,237 - - Dec. 31,1994 Dec. 31, 1993 $2,845,967 $2,774,511 999,985 1,093,895 125,000 125,000 887,967 856,559 STATISTICS Average Gross Electric Annual Utility Plant Use Per December 31, kWh Residential Electric (Thousands of Sales Customer Customers Employees Dollars)(a) (Millions) (kWh) (Average) (December 31) 1997 $2,312,628 13,340 6,528 407,642 1,254 1996 2,382,009 13,601 6,567 407,082 1,279 1995 2,469,474 11,001 6,524(b) 406,077 1,325 1994 2,521,960 11,008 6,768 400,775 1,374 1993 2,590,644 11,146 6,817 397,277 1,426 STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) (Restated) Quarter Ended (c) 1997 March 31 June 30 Sept.30 Dec. 31 Operating Revenues... $278,321 $257,098 $285,390 $287,650 Operating Income..... $ 44,776 $ 34,190 $ 32,166 $ 32,892 Net Income........... $ 32,295 $ 21,289 $ 18,900 $ 19,688 1996 March 31 June 30 Sept.30 Dec. 31 Operating Revenues... $269,540 $261,897 $296,719 $282,013 Operating Income..... $ 44,865 $ 42,220 $ 46,864 $ 21,809 Net Income........... $ 28,742 $ 24,050 $ 30,576 $ 14,097 (a) Includes reclassification of the unamortized acquisition costs to gross utility plant. (b) Effective January 1, 1996, the amounts shown reflect billed and unbilled sales. 1995 has been restated to reflect this change. (c) Reclassifications of prior data have been made to conform with the current presentation. EX-27.1 6 DATA SCHEDULE FOR NU
UT 0000072741 NORTHEAST UTILITIES AND SUBSIDIARIES 1,000 YEAR DEC-31-1997 DEC-31-1997 PER-BOOK 6,463,158 704,701 970,673 2,275,880 0 10,414,412 684,211 932,493 707,522 2,170,085 245,750 136,200 3,645,659 50,000 0 0 244,560 30,250 30,427 177,304 3,684,177 10,414,412 3,834,806 1,948 3,631,374 3,644,024 190,782 (29,179) 172,305 271,981 (99,676) 30,286 (129,962) 32,134 282,095 377,221 (1.01) 0.00 EX-27.2 7 DATA SCHEDULE FOR CLP
UT 0000023426 THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES 1,000 YEAR DEC-31-1997 DEC-31-1997 PER-BOOK 3,737,113 493,848 519,799 1,330,463 0 6,081,223 122,229 641,333 419,972 1,183,534 151,250 116,200 2,023,316 96,300 0 0 20,011 3,750 18,042 140,076 2,328,744 6,081,223 2,465,587 (67,009) 2,532,642 2,473,206 (7,619) (5,484) (5,530) 134,067 (139,597) 15,221 (154,818) 5,989 132,127 72,793 0.00 0.00 EX-27.3 8 DATA SCHEDULE FOR WME
UT 0000106170 WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY 1,000 YEAR DEC-31-1997 DEC-31-1997 PER-BOOK 775,114 123,349 63,630 217,035 0 1,179,128 26,812 151,171 58,608 236,591 19,500 20,000 386,849 29,350 0 0 9,800 1,500 217 32,670 442,651 1,179,128 426,447 (16,168) 441,338 426,196 251 418 1,695 29,155 (27,460) 3,140 (30,600) 15,004 26,046 27,660 0.00 0.00 EX-27.4 9 DATA SCHEDULE FOR PSNH
UT 0000315256 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 1,000 YEAR DEC-31-1997 DEC-31-1997 PER-BOOK 1,722,572 27,274 342,520 744,793 0 2,837,159 1 423,713 170,501 594,215 75,000 0 516,485 0 0 0 170,000 25,000 799,450 122,363 534,646 2,837,159 1,108,459 88,841 877,985 964,435 144,024 2,071 143,704 51,532 92,172 11,925 80,247 85,000 51,259 232,703 0.00 0.00 -----END PRIVACY-ENHANCED MESSAGE-----