10-Q 1 cover.txt FORM 10-Q SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549-1004 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2002 ------------------ 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) Energy Park 780 North Commercial Street Manchester, New Hampshire 03101-1134 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 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 the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date: Company - Class of Stock Outstanding at October 31, 2002 ------------------------ ------------------------------- Northeast Utilities Common shares, $5.00 par value 128,507,340 shares The Connecticut Light and Power Company Common stock, $10.00 par value 6,811,994 shares Public Service Company of New Hampshire Common stock, $1.00 par value 388 shares Western Massachusetts Electric Company Common stock, $25.00 par value 434,653 shares GLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report: COMPANIES CL&P....................... The Connecticut Light and Power Company NAEC....................... North Atlantic Energy Corporation NGC........................ Northeast Generation Company NGS........................ Northeast Generation Services Company NU or the company.......... Northeast Utilities NU system.................. The Northeast Utilities system companies, including NU and its wholly owned operating subsidiaries: CL&P, PSNH, WMECO, NAEC, and Yankee Gas NUEI Parent................ NU Enterprises, Inc. PSNH....................... Public Service Company of New Hampshire Select Energy.............. Select Energy, Inc. (including its wholly owned subsidiary SENY) SENY....................... Select Energy New York, Inc. SESI....................... Select Energy Services, Inc. WMECO...................... Western Massachusetts Electric Company Yankee..................... Yankee Energy System, Inc. Yankee Gas................. Yankee Gas Services Company YESCO...................... Yankee Energy Services Company NUCLEAR UNIT Seabrook................... Seabrook Unit No. 1, a 1,148 megawatt nuclear electric generating unit completed in 1986; Seabrook went into service in 1990. REGULATORS DPUC....................... Connecticut Department of Public Utility Control DTE........................ Massachusetts Department of Telecommunications and Energy NHPUC...................... New Hampshire Public Utilities Commission SEC........................ Securities and Exchange Commission OTHER CSC........................ Connecticut Siting Council EITF....................... Emerging Issues Task Force EPS........................ Earnings per share FASB....................... Financial Accounting Standards Board FPPAC...................... Fuel and purchased-power adjustment clause IERM....................... Infrastructure Expansion Rate Mechanism kWh........................ Kilowatt-hour MW......................... Megawatts NU 2001 Form 10-K.......... The NU system combined 2001 Form 10-K as filed with the SEC O&M........................ Operation and maintenance SFAS....................... Statement of Financial Accounting Standards Northeast Utilities and Subsidiaries The Connecticut Light and Power Company and Subsidiaries Public Service Company of New Hampshire and Subsidiaries Western Massachusetts Electric Company and Subsidiary TABLE OF CONTENTS ----------------- Page ---- Part I. Financial Information Item 1. Consolidated Financial Statements (Unaudited) and Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations For the following companies: Northeast Utilities and Subsidiaries Consolidated Balance Sheets - September 30, 2002 and December 31, 2001.............. 2 Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2002 and 2001........................... 4 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2002 and 2001......... 5 Management's Discussion and Analysis of Financial Condition and Results of Operations......... 6 Independent Accountants' Report....................... 29 Notes to Consolidated Financial Statements (unaudited - all companies)................................. 30 The Connecticut Light and Power Company and Subsidiaries Consolidated Balance Sheets - September 30, 2002 and December 31, 2001.............. 50 Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2002 and 2001........................... 52 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2002 and 2001......... 53 Management's Discussion and Analysis of Financial Condition and Results of Operations......... 54 Public Service Company of New Hampshire and Subsidiaries Consolidated Balance Sheets - September 30, 2002 and December 31, 2001.............. 60 Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2002 and 2001........................... 62 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2002 and 2001......... 63 Management's Discussion and Analysis of Financial Condition and Results of Operations......... 64 Western Massachusetts Electric Company and Subsidiary Consolidated Balance Sheets - September 30, 2002 and December 31, 2001.............. 70 Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2002 and 2001........................... 72 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2002 and 2001......... 73 Management's Discussion and Analysis of Financial Condition and Results of Operations......... 74 Item 3. Quantitative and Qualitative Disclosures About Market Risk......................... 77 Item 4. Controls and Procedures............................... 77 Part II. Other Information Item 1. Legal Proceedings..................................... 78 Item 6. Exhibits and Reports on Form 8-K...................... 79 Signatures and Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.................................... 82 NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2002 2001 -------------- -------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash and cash equivalents............................ $ 70,726 $ 96,658 Investments in securitizable assets.................. 156,797 206,367 Receivables, net..................................... 665,205 659,759 Unbilled revenues.................................... 96,719 126,398 Fuel, materials and supplies, at average cost........ 131,937 108,516 Special deposits..................................... 12,702 13,036 Unrealized gains on mark-to-market transactions...... 135,147 147,217 Prepayments and other................................ 142,716 69,824 -------------- -------------- 1,411,949 1,427,775 -------------- -------------- Property, Plant and Equipment: Electric utility..................................... 5,981,390 5,743,575 Gas utility.......................................... 666,971 634,884 Competitive energy................................... 995,250 994,901 Other................................................ 200,418 195,741 -------------- -------------- 7,844,029 7,569,101 Less: Accumulated provision for depreciation....... 3,531,643 3,418,577 -------------- -------------- 4,312,386 4,150,524 Construction work in progress........................ 308,720 289,889 Nuclear fuel, net.................................... 22,797 32,564 -------------- -------------- 4,643,903 4,472,977 -------------- -------------- Deferred Debits and Other Assets: Regulatory assets ................................... 3,089,272 3,287,537 Goodwill and other purchased intangible assets, net.. 343,871 333,123 Prepaid pension...................................... 287,834 232,398 Nuclear decommissioning trusts, at market............ 63,486 61,713 Other ............................................... 475,886 468,007 -------------- -------------- 4,260,349 4,382,778 -------------- -------------- Total Assets........................................... $ 10,316,201 $ 10,283,530 ============== ============== The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2002 2001 -------------- -------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to banks............................... $ 315,733 $ 290,500 Long-term debt - current portion..................... 52,439 50,462 Accounts payable..................................... 571,550 622,320 Accrued taxes........................................ 49,957 26,203 Accrued interest..................................... 58,198 35,659 Unrealized losses on mark-to-market transactions..... 53,416 90,808 Other................................................ 210,949 161,277 -------------- -------------- 1,312,242 1,277,229 -------------- -------------- Rate Reduction Bonds................................... 1,935,467 2,018,351 -------------- -------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes.................... 1,489,232 1,491,394 Accumulated deferred investment tax credits.......... 110,584 120,071 Deferred contractual obligations..................... 191,117 216,566 Other................................................ 699,706 633,523 -------------- -------------- 2,490,639 2,461,554 -------------- -------------- Capitalization: Long-Term Debt....................................... 2,272,402 2,292,556 -------------- -------------- Preferred Stock...................................... 116,200 116,200 -------------- -------------- Common Shareholders' Equity: Common shares, $5 par value - authorized 225,000,000 shares; 149,375,000 shares issued and 129,257,380 shares outstanding in 2002 and 148,890,640 shares issued and 130,132,136 shares outstanding in 2001............................... 746,875 744,453 Capital surplus, paid in........................... 1,109,798 1,107,609 Deferred contribution plan - employee stock ownership plan................................... (91,982) (101,809) Retained earnings.................................. 727,204 678,460 Accumulated other comprehensive income/(loss)...... 6,095 (32,470) Treasury stock 16,143,264 shares in 2002 and 14,359,628 shares in 2001.................... (308,739) (278,603) -------------- -------------- Common Shareholders' Equity.......................... 2,189,251 2,117,640 ------------- ------------- Total Capitalization................................... 4,577,853 4,526,396 ------------- ------------- Commitments and Contingencies (Note 2) Total Liabilities and Capitalization................... $ 10,316,201 $ 10,283,530 ============== ============== The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, ------------------------------------------------------------ 2002 2001 2002 2001 -------------- -------------- -------------- -------------- (Thousands of Dollars, except share information) Operating Revenues..................................... $ 1,361,045 $ 1,530,669 $ 3,770,092 $ 4,669,663 -------------- -------------- -------------- -------------- Operating Expenses: Operation - Fuel, purchased and net interchange power......... 797,498 985,065 2,133,833 2,880,938 Other............................................. 184,110 194,778 580,865 592,757 Maintenance.......................................... 68,271 59,733 194,032 208,152 Depreciation......................................... 48,150 43,562 146,775 154,082 Amortization......................................... 97,336 94,505 211,112 900,459 Taxes other than income taxes........................ 47,585 39,648 177,043 170,739 Gain on sale of utility plant........................ - - - (643,909) -------------- -------------- -------------- -------------- Total operating expenses........................ 1,242,950 1,417,291 3,443,660 4,263,218 -------------- -------------- -------------- -------------- Operating Income....................................... 118,095 113,378 326,432 406,445 Other Income, Net...................................... 32,059 17,724 19,715 190,644 -------------- -------------- -------------- -------------- Income Before Interest and Income Tax Expense.......... 150,154 131,102 346,147 597,089 -------------- -------------- -------------- -------------- Interest Expense: Interest on long-term debt........................... 35,347 30,995 107,105 109,906 Interest on rate reduction bonds..................... 28,751 30,883 87,539 57,703 Other interest....................................... 3,615 8,404 8,964 41,413 -------------- -------------- -------------- -------------- Interest expense, net........................... 67,713 70,282 203,608 209,022 -------------- -------------- -------------- -------------- Income Before Income Tax Expense....................... 82,441 60,820 142,539 388,067 Income Tax Expense..................................... 32,476 25,185 42,296 165,964 -------------- -------------- -------------- -------------- Income Before Preferred Dividends of Subsidiaries...... 49,965 35,635 100,243 222,103 Preferred Dividends of Subsidiaries.................... 1,390 1,004 4,169 6,145 -------------- -------------- -------------- -------------- Income Before Cumulative Effect of Accounting Change... 48,575 34,631 96,074 215,958 Cumulative effect of accounting change, net of tax benefit of $14,908.......................... - - - (22,432) -------------- -------------- -------------- -------------- Net Income............................................. $ 48,575 $ 34,631 $ 96,074 $ 193,526 ============== ============== ============== ============== Basic and Fully Diluted Earnings Per Common Share: Income before cumulative effect of accounting change. $ 0.38 $ 0.26 $ 0.74 $ 1.57 Cumulative effect of accounting change, net of tax benefit................................. - - - (0.16) -------------- -------------- -------------- -------------- Basic and Fully Diluted Earnings Per Common Share...... $ 0.38 $ 0.26 $ 0.74 $ 1.41 ============== ============== ============== ============== Basic Common Shares Outstanding (average).............. 129,344,724 133,540,631 129,508,840 137,120,689 ============== ============== ============== ============== Fully Diluted Common Shares Outstanding (average)...... 129,508,794 133,869,227 129,737,249 137,457,694 ============== ============== ============== ============== The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, ------------------------------- 2002 2001 --------------- -------------- (Thousands of Dollars) Operating Activities: Income before preferred dividends of subsidiaries........... $ 100,243 $ 222,103 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation.............................................. 146,775 154,082 Deferred income taxes and investment tax credits, net..... (54,207) (141,460) Amortization.............................................. 211,112 900,459 Net amortization/(deferral) of recoverable energy costs... 19,557 (37,402) Gain on sale of utility plant............................. - (643,909) Cumulative effect of accounting change.................... - (22,432) Net other (uses)/sources of cash.......................... 4,524 (53,016) Changes in working capital: Receivables and unbilled revenues, net.................... 29,223 (14,067) Fuel, materials and supplies.............................. (23,285) 60,145 Accounts payable.......................................... (52,846) 95,841 Accrued taxes............................................. 23,754 58,571 Investments in securitizable assets....................... 49,570 (107,446) Other working capital (excludes cash)..................... 12,678 (72,294) ------------ ------------- Net cash flows provided by operating activities............... 467,098 399,175 ------------ ------------- Investing Activities: Investments in plant: Electric, gas and other utility plant..................... (326,885) (314,543) Nuclear fuel.............................................. (434) (3,502) ------------ ------------- Cash flows used for investments in plant.................... (327,319) (318,045) Investments in nuclear decommissioning trusts............... (7,100) (119,272) Net proceeds from the sale of utility plant................. - 1,027,733 Buyout/buydown of IPP contracts............................. - (1,128,708) Payment for acquisition of competitive energy subsidiaries.. (15,300) - Other investment activities, net............................ 14,057 (146,260) ------------ ------------- Net cash flows used in investing activities................... (335,662) (684,552) ------------ ------------- Financing Activities: Issuance of common shares................................... 7,445 1,751 Repurchase of common shares................................. (30,136) (241,589) Issuance of long-term debt.................................. 263,000 263,000 Issuance of rate reduction bonds............................ 50,000 2,118,400 Retirement of rate reduction bonds.......................... (132,883) - Net increase/(decrease) in short-term debt.................. 25,233 (873,477) Reacquisitions and retirements of long-term debt............ (285,146) (660,385) Reacquisitions and retirements of preferred stock........... - (60,768) Retirement of monthly income preferred securities........... - (100,000) Retirement of capital lease obligation...................... - (180,000) Cash dividends on preferred stock........................... (4,169) (6,145) Cash dividends on common shares............................. (50,164) (44,514) Other financing activities, net............................. (548) - ------------ ------------- Net cash flows (used in)/provided by financing activities..... (157,368) 216,273 ------------ ------------- Net decrease in cash and cash equivalents..................... (25,932) (69,104) Cash and cash equivalents - beginning of period............... 96,658 200,017 ------------ ------------- Cash and cash equivalents - end of period..................... $ 70,726 $ 130,913 ============ ============== The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES Management's Discussion and Analysis of Financial Condition and Results of Operations This discussion should be read in conjunction with the consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2002 Form 10-Qs, current reports on Form 8-K dated July 23, 2002, August 2, 2002, August 14, 2002, October 8, 2002, and October 21, 2002, and the 2001 Form 10-K. All per share amounts are reported on a fully diluted basis. FINANCIAL CONDITION Overview Northeast Utilities and subsidiaries (NU or the company) earned $48.6 million, or $0.38 per share, during the third quarter of 2002, compared with earnings of $34.6 million, or $0.26 per share, during the same period of 2001. For the first nine months of 2002, NU earned $96.1 million, or $0.74 per share, compared with $193.5 million, or $1.41 per share, during the same period of 2001. During the third quarter of 2002, NU recorded a net after-tax gain of $14.5 million, or $0.11 per share, primarily related to the elimination of reserves associated with NU's ownership shares of Seabrook unit 2. During the first quarter of 2002, NU recorded after-tax charges of $10 million, or $0.08 per share, associated with the write-down of our investments in NEON Communications, Inc. (NEON) and Accumentrics Corporation. Excluding these items, NU earned $34.1 million, or $0.27 per share, during the third quarter of 2002 and $91.6 million, or $0.71 per share, during the first nine months of 2002. On November 1, 2002, a subsidiary of the FPL Group, Inc. (FPL) purchased NU's 40.04 percent combined shares of Seabrook. During the fourth quarter NU will record approximately $10 million of additional net after-tax gains associated with the sale. During the first nine months of 2001, NU recorded a gain related to the sale of the Millstone nuclear units, which occurred in March 2001, a loss related to the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, and a loss related to the forward repurchase of 10.1 million NU common shares. Excluding these items, NU earned $126.5 million, or $0.92 per share, during the first nine months of 2001. The decline in NU's earnings for the first nine months of 2002 resulted primarily from weaker performance at the competitive energy subsidiaries. During the first nine months of 2002, NU's competitive energy subsidiaries lost $39.9 million, compared with essentially break-even results during the same period of 2001, before the cumulative effect of an accounting change of $22 million. These weaker results are related primarily to mild weather in the first quarter of 2002, which caused significant losses serving unregulated retail gas and electric customers, natural gas trading losses in March and April 2002, and low water flows, which reduced conventional hydroelectric production. NU's competitive energy subsidiaries lost $9 million, or $0.07 per share, in the third quarter of 2002, compared with a loss of $9.7 million, or $0.07 per share, during the same period of 2001. NU's revenues during the first nine months of 2002 decreased to $3.8 billion from $4.7 billion during the same period of 2001. The decrease in revenues relates to lower wholesale marketing revenues at the competitive energy subsidiaries as a result of wholesale contracts not being renewed at the same prices and volumes for 2002. Also contributing to the revenue decrease is lower regulated company wholesale revenues from lower sales of energy and capacity in New Hampshire and from 2001 sales of output from the Millstone units. Regulated retail revenues also decreased, primarily due to rate decreases associated with industry restructuring and lower industrial sales to New Hampshire customers. NU's regulated electric subsidiaries benefited from an extremely hot summer. Third quarter 2002 residential electric sales increased 10.9 percent and commercial electric sales increased 6.0 percent, while industrial sales decreased 1.6 percent due to weaker economic conditions compared with the same period of 2001. Overall, third quarter 2002 total electric sales increased 6.4 percent compared with the same period of 2001. During the first nine months of 2002, total electric sales increased 0.6 percent compared with the same period of 2001. Revenues of NU's competitive energy subsidiaries were reduced significantly from amounts previously reported as a result of recently released accounting guidance related to the classification of revenues and expenses associated with energy trading contracts. As a result, NU's revenues and expenses for the first six months of 2002 have been reduced by $1.2 billion with no change in net income. The retroactive reclassification of revenues and expenses, combined with the unavailability of the company's previous independent public accountants, has resulted in the requirement to have the company's financial information as of and for the year ended December 31, 2001, reaudited. Management does not expect the reaudit of this financial information to have a material impact on amounts previously reported other than the reclassification of revenues and expenses itself. NU's trading revenues and expenses for all periods presented have been reclassified. The changes to 2001 information that was previously reported are included in Note 1C, "New Accounting Standards," to the consolidated financial statements. On October 25, 2002, the Emerging Issues Task Force (EITF) decided to rescind the consensus reached in EITF Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities," under which the competitive energy subsidiaries currently account for trading activities on a mark-to-market basis. For information regarding this change in accounting, which will impact the competitive energy subsidiaries in the future, see Note 1C, "New Accounting Standards," to the consolidated financial statements. NU's earnings per share in both 2002 and 2001 benefited from the company's ongoing share repurchase program. NU had approximately 129.3 million shares outstanding as of September 30, 2002, compared with 130.1 million shares outstanding as of December 31, 2001. NU repurchased approximately 14.3 million shares in 2001 and approximately 1.8 million additional shares during the first nine months of 2002. NU's Board of Trustees has authorized the repurchase of approximately 9 million additional shares through June 30, 2003. NU has repurchased approximately 880,000 shares at an average share price of $14.98 from October 1, 2002 through October 31, 2002. Earnings before preferred dividends at The Connecticut Light and Power Company (CL&P), NU's largest regulated subsidiary, totaled $29.3 million for the third quarter of 2002, and $62.4 million for the first nine months of 2002, compared with $18.8 million for the third quarter of 2001 and $75.9 million for the first nine months of 2001. The third quarter 2002 increase was primarily due to a weather-driven 7.6 percent increase in retail sales, compared with the same period of 2001. The lower earnings for the first nine months of 2002 were primarily due to an after-tax gain of $19.1 million recorded during the first quarter of 2001 as a result of the Millstone sale, offset by the aforementioned increase in retail sales. Combined earnings before preferred dividends at Public Service Company of New Hampshire (PSNH) and North Atlantic Energy Corporation (NAEC) totaled $36.4 million for the third quarter of 2002, and $67.1 million for the first nine months of 2002, compared with $21.8 million for the third quarter of 2001 and $76.1 million for the first nine months of 2001. The third quarter 2002 increase was primarily due to the elimination of the Seabrook-related reserve at NAEC. The lower earnings for the first nine months of 2002 were primarily due to an after-tax gain of $15.5 million recorded during the first quarter of 2001 associated with the sale of PSNH's share of the Millstone 3 nuclear unit and to a greater than 10 percent retail rate reduction that took effect on May 1, 2001, in connection with industry restructuring, offset by the aforementioned elimination of the Seabrook reserve at NAEC. Earnings before preferred dividends at Western Massachusetts Electric Company (WMECO) totaled $4.7 million during the third quarter of 2002, and $26.9 million for the first nine months of 2002, compared with $3.9 million for the third quarter of 2001 and $8.7 million for the first nine months of 2001. The third quarter 2002 increase was primarily due to hotter weather, compared with the same period of 2001. The higher earnings for the first nine months of 2002 were primarily due to the recognition during 2002 of approximately $13 million in tax credits as a result of a regulatory decision received during the second quarter of 2002 and due to a first quarter 2001 refueling outage at the Millstone 3 nuclear unit. Yankee Energy System, Inc. (Yankee) lost $5.8 million during the third quarter of 2002 and earned $6.3 million during the first nine months of 2002, compared with earnings of $3.2 million during the third quarter of 2001 and earnings of $12.1 million during the first nine months of 2001. The lower earnings for 2002 were primarily due to the recording of approximately $10 million after-tax in August of 2001 related to a favorable property tax settlement. Future Outlook NU currently estimates it will earn between $1.10 per share and $1.30 per share in 2002. That estimate assumes that NU will earn between $0.36 and $0.56 per share in the fourth quarter of 2002, including net after-tax gains of approximately $10 million related to the sale of Seabrook in the fourth quarter of 2002, compared to $0.38 per share in 2001. The range also assumes losses of between $10 million and $20 million at NU's competitive energy subsidiaries in the fourth quarter of 2002, compared with earnings of $5.3 million in the fourth quarter of 2001. The reduction in fourth quarter 2002 earnings compared to the fourth quarter of 2001 is primarily due to reduced gains related to contract restructuring. Offsetting weaker projected performance at NU's competitive businesses will be a lower share count and an expected return to normal weather from the mild November and December of 2001. The earnings range also reflects management's uncertainty over the outcome of regulatory dockets in Connecticut, New Hampshire and Massachusetts related to the recovery of certain stranded costs, which management believes were prudently incurred and are probable of recovery. NU also expects to earn between $1.10 per share and $1.30 per share in 2003. That estimate assumes earnings of between $1.05 per share and $1.15 per share at NU's regulated businesses and between $0.15 and $0.25 at NU's competitive energy subsidiaries. NU also assumes it will incur after-tax costs of approximately $0.10 per share at the parent company, primarily related to debt expenses. The 2003 earnings range assumes significantly lower earnings at NU's regulated businesses and significantly improved results at NU's competitive businesses, compared with 2002. Lower earnings at the regulated businesses are related primarily to the absence of 2002 gains related to Seabrook, lower investment tax credits and to much lower pension income. Improved results at NU's competitive energy subsidiaries are projected as a result of an improvement to modest profitability in its trading function and to break-even in its retail marketing function. The competitive energy subsidiaries are expected to lose approximately $50 million to $60 million in 2002. As a result of continued poor performance in the equity markets in 2002, the NU system is projecting approximately $34 million of pre-tax pension income in 2003, a decrease from approximately $73 million in 2002 and approximately $101 million in 2001. The lower 2003 pension income primarily affects NU's regulated businesses, particularly CL&P and WMECO. Offsetting the impact the lower pension income will have on earnings is the amount of pension income that will be capitalized as utility plant. Approximately 30 percent of pension income has been capitalized as utility plant in the past along with other costs related to employees who work on capital projects. The percentage of pension income capitalized depends on the scope of capital programs at the regulated businesses. The lower pension income and higher projected health care costs will also be partially offset by a reduction in the number of employees at NU. In September 2002, the NU system reduced its workforce by approximately 200 employees and expects to reduce its contractor workforce by approximately 100 contractors by the beginning of 2003. Together, these workforce reductions are expected to result in approximately a $20 million pre-tax reduction in costs in 2003. Management believes that most of the cost of the workforce reduction, which was approximately $5 million, is recoverable from ratepayers as a stranded cost related to industry restructuring. Liquidity NU maintained a high level of liquidity throughout the first nine months of 2002, and maintaining liquidity remains a significant focus for NU. As of September 30, 2002, NU had $70.7 million in cash and cash equivalents on hand. In addition to cash and cash equivalents on hand, NU has access to approximately $415 million through available credit facilities. NU expects its cash position to further improve in the fourth quarter of 2002 due to the sale of CL&P's and NAEC's combined 40.04 percent shares of Seabrook on November 1, 2002. CL&P and NAEC received approximately $370 million in total gross proceeds, which are subject to certain true-up adjustments. Of the total cash proceeds NU received from the Seabrook sale, a portion of these proceeds were used to repay all $90 million of NAEC's outstanding debt, and will be used to return all of NAEC's equity, which totaled $55.7 million as of September 30, 2002, to NU and pay between $90 million and $100 million in taxes. The remaining proceeds were refunded to PSNH through the Seabrook Power Contracts. PSNH will use the proceeds refunded from NAEC to recover stranded costs and repay approximately $60 million of debt with any remaining amounts being available to be returned to NU. The net gain from the sale related to CL&P's share of Seabrook primarily will be used to offset stranded costs, and the cash proceeds received by CL&P will be used to meet its capital requirements. NU additionally received approximately $14 million from an unaffiliated owner of Seabrook upon the close of the sale. NU expects to use these additional proceeds, the $55.7 million from NAEC and any amounts received from PSNH to reduce short-term borrowings, fund continued share repurchases, and continue to maintain a high level of liquidity within the NU system. NU had no significant financing activity in the third quarter of 2002. In November 2002, NU expects to refinance its two principal credit lines. It expects to decrease to $300 million from $350 million a line of credit for its regulated subsidiaries. It also expects to increase to $350 million its $300 million line of credit for the parent company and NU's competitive energy subsidiaries. As of September 30, 2002, PSNH, WMECO and Yankee had $55 million, $55 million, and $40 million, respectively, outstanding under the regulated company credit line. Also, as of September 30, 2002, NU parent and NU's competitive energy subsidiaries had a total of $75 million of direct borrowings and $70.4 million of letters of credit outstanding. Total direct borrowings included $55 million, $10 million, and $10 million advanced by NU parent through the NU system Money Pool to Select Energy, Inc. (Select Energy) Northeast Generation Services Company (NGS) and Select Energy Services, Inc. (SESI), respectively. The $70.4 million represents letters of credit issued to counterparties with whom Select Energy has energy contracts and to other parties. NU projects a modest level of system financings over the next three to six months. CL&P is currently contemplating the issuance of up to $200 million of debt to refinance its spent nuclear fuel obligations. WMECO has applied to the Massachusetts Department of Telecommunications and Energy (DTE) to issue $100 million of debt to refinance its existing short-term debt and spent nuclear fuel obligations. Yankee Gas Services Company (Yankee Gas) may seek to issue up to $75 million of debt to reduce short-term debt, which totaled $66 million as of September 30, 2002. In 2001, NU applied to the Securities and Exchange Commission (SEC) to increase to $750 million from $500 million its authority to provide credit assurance in the form of guarantees and letters of credit for the financial performance obligations of certain of its competitive energy subsidiaries, including Select Energy. In addition, NU has applied to the SEC for authority to exempt Select Energy, Select Energy New York, Inc. (SENY) and certain other subsidiaries from the SEC rule limiting NU's "aggregate investment" in such companies to 15 percent of NU's most recent quarterly capitalization. The SEC has not indicated when, or if, it will authorize these increases, and its failure to do so could restrict Select Energy's future growth potential. Over the longer term, a low level of maturities and sinking fund payments will mitigate the NU system's need to obtain funds from the capital markets. In 2003, 2004, and 2005, total system maturities total $54 million, $58 million, and $87 million, respectively. NU's net cash flows provided by operating activities increased to $467.1 million in the first nine months of 2002, compared with $399.2 million during the same period of 2001. Cash flows provided by operating activities increased primarily due to taxes payable in 2001 in connection with the sale of the Millstone units. Also contributing to the increase is the amortization of recoverable energy costs in 2002 compared with deferrals in 2001. Changes in working capital items also contributed to the increase. There was a lower level of investing and financing activities in the first nine months of 2002, as compared to the same period of 2001, primarily due to the sale of the Millstone units, the buyout and buydown of independent power producer contracts, and the issuance of CL&P, PSNH and WMECO rate reduction certificates and bonds in 2001. The level of NU's common dividends totaled $50.2 million in the first nine months of 2002, compared with $44.5 million in the same period of 2001. This increase was a result of NU paying a $0.10 per share quarterly common dividend in the first two quarters of 2001, a $0.125 per share quarterly common dividend in the last two quarters of 2001 and the first two quarters of 2002, and a $0.1375 dividend in the third quarter of 2002. The increase in common dividends was partially offset by a lower share count. On May 14, 2002, NU's Board of Trustees approved payment of a quarterly cash dividend of $0.1375 per share, payable on September 30, 2002, to shareholders of record as of September 1, 2002. This increase is consistent with the company's announced intention of raising the dividend by 10 percent annually. Management has stated that NU may consider raising the dividend target beyond the previously stated goal of paying out approximately 50 percent of regulated company earnings. Such a program will be dependent upon numerous factors, including NU's ability to meet earnings targets and the judgment of its Board of Trustees at the time dividends are declared. Competitive Energy Subsidiaries Subsidiaries: NU's competitive energy subsidiaries include Select Energy and its subsidiary SENY (collectively Select Energy), Northeast Generation Company (NGC), Holyoke Water Power Company (HWP), SESI and NGS. Select Energy engages in wholesale and retail energy marketing activities and energy trading activities. NU's competitive energy subsidiaries own 1,439 megawatts (MW) of generation capacity, consisting of 1,292 MW at NGC and 147 MW at HWP. On June 17, 2002, the air circuit breaker in one of NGC's four 270-megawatt pumped storage units at Northfield Mountain was damaged by fire. This unit returned to service on September 4, 2002. Northfield Mountain's other three units were not damaged and continued to operate. NGC carries property insurance and business interruption insurance for Northfield Mountain. As a result, the fire did not have a material effect on NU's or NGC's financial position or results of operations. SESI performs energy management services for large industrial, commercial and institutional facilities, including the United States Department of Defense, and engages in energy related construction services. NGS operates and maintains NGC's and HWP's generation assets and provides third-party electrical and engineering contracting services. Consistent with its business strategy, the competitive energy subsidiaries acquired certain assets and assumed certain liabilities of an electrical services company and a telecommunications, construction and service company for an aggregate purchase price of $15.3 million on July 1, 2002. Financial results of the acquired companies are included in NU's results of operations since July 1, 2002. For further information regarding this acquisition, see Note 3, "Goodwill and Other Intangible Assets," to the consolidated financial statements. Results: NU's competitive businesses lost $39.9 million after-tax through the first three quarters of 2002 and are expected to lose another $10 million to $20 million after-tax in the fourth quarter of 2002. This compares to break-even results in the first three quarters of 2001 and a profit of approximately $5 million after-tax in the fourth quarter of 2001. Those break-even results for the first three quarters of 2001 exclude a $22 million cumulative effect of an accounting change related to the negative fair value of derivative contracts, primarily at Select Energy's retail marketing business. Most of these contracts expire in 2002. In the first quarter of 2002, NU's competitive businesses lost approximately $22 million, which included after-tax gains of $7 million associated with the renegotiation of certain long-term supply contracts. The first quarter losses included an after-tax loss of $10.6 million in the energy trading area, primarily as a result of a steep increase in the cost of natural gas in the month of March. The competitive retail business lost $13.9 million in the first quarter of 2002 primarily due to unusually mild weather that reduced the consumption of natural gas, requiring Select Energy to sell excess natural gas back into the market at lower prices. In the second quarter of 2002, the competitive businesses lost approximately $9 million. Much of that loss was related to $7.1 million of after-tax losses in the trading area, again resulting from higher natural gas prices in April 2002. In the third quarter of 2002, the competitive businesses lost approximately $9 million, primarily due to unexpectedly high demand brought on by an extremely hot summer. The hot weather caused Select Energy to buy electricity in the spot market as wholesale electricity prices were rising. The trading function lost $1.3 million after-tax in the third quarter. Outlook: In the fourth quarter of 2002 management expects Select Energy to continue to be negatively affected by energy price volatility. However, management has taken steps to purchase virtually all of its projected electricity requirements for November and December, providing more predictability to the quarter's financial results. Management is taking a number of steps to return the competitive energy businesses to profitability in 2003. It has acquired additional businesses in the energy services field and expects that projected profits of $5 million in 2002 will increase in 2003. It has considerably reduced the amount of capital at risk in the trading operation and projects that after-tax losses in the range of $16 million to $19 million in 2002 will turn into modest profits in 2003. Many unprofitable retail contracts expire in 2002. Select Energy plans to size the retail organization to fit a reduced level of business and expects to better manage volumetric risk, particularly in the winter heating months. As a result, management expects to roughly break-even in the retail business in 2003, compared with projected losses of $25 million to $28 million in 2002. In the wholesale marketing area, Select Energy, including NGC, expects to have modest profits in 2003, compared with projected losses of $15 million to $19 million in 2002. Select Energy expects the improvement to come from improved results on its contract with CL&P, which has negatively impacted Select Energy's results by approximately $36.4 million after-tax for the first nine months of 2002, and improved management of the supplies associated with its full requirements contracts. This forecast assumes that Select Energy will be successful in securing a significant amount of new business at acceptable margins. CL&P's standard offer service purchases from Select Energy represented $375.7 million of total competitive energy subsidiaries' revenues for the first nine months of 2002, compared with $378.5 million for the first nine months of 2001. Other transactions between CL&P and Select Energy amounted to $97.2 million in revenues for Select Energy for the first nine months of 2002, compared with $116.8 million for the same period in 2001. These amounts are eliminated in consolidation. In the second quarter of 2002, the competitive energy subsidiaries conducted studies of the depreciable lives of certain generation and software assets. The impact of these studies was to lengthen the useful lives of those generation assets by 20 years to an average of 58 remaining years and to shorten the useful lives of that software to 1.5 remaining years effective for the second quarter of 2002. As a result of these studies, NU's operating expenses decreased by approximately $3 million since the beginning of the second quarter of 2002 and are expected to decrease by approximately $6 million annually. Competitive Energy Subsidiaries' Market and Other Risks Overview: NU's competitive energy subsidiaries are exposed to certain market risks inherent in their business activities. Certain competitive energy subsidiaries, primarily Select Energy, enter into contracts of varying lengths of time to buy and sell energy commodities, including electricity, natural gas and oil. Market risk represents the risk of loss that may impact Select Energy's financial results due to adverse changes in commodity market prices. Wholesale and Retail Marketing: A significant portion of Select Energy's wholesale marketing business is providing energy to full requirements customers, primarily regulated distribution companies. Under full requirements contract terms, Select Energy is required to provide the total energy requirement for the customers' load at all times. A key component of Select Energy's risk management strategy is focused on managing the volume and price risks of full requirements contracts. These risks include significant fluctuations in supply and demand due to numerous factors such as weather, plant availability, transmission congestion, and potentially volatile price fluctuations. As discussed above, Select Energy's year to date 2002 results were negatively impacted by weather patterns that resulted in contracted supply exceeding demand in the warmer than expected winter and committed supply during certain summer months purchased at prices higher than those forecasted. The competitive energy subsidiaries manage their portfolio of wholesale and retail marketing contracts and assets to maximize value and minimize associated risks. The lengths of contracts to buy and sell energy vary in duration from daily/hourly to several years. At any point in time the wholesale and retail marketing portfolio may be long (purchases exceed sales) or short (sales exceed purchases). Portfolio and risk management disciplines with established policies and procedures are used to manage exposures to market risks. At forward market prices in effect at September 30, 2002, the wholesale marketing portfolio, which includes the CL&P standard offer service contract and other contracts that extend to 2013, had a positive mark-to- market position. This positive mark-to-market position will impact Select Energy's gross margin in the future. However, there is significant volatility in the energy commodities market that will impact this position between now and when the contracts are settled. Portfolio volatility reflects fluctuations in value due to changes in energy prices in the region, new transactions entered into during the period and positions settling during the period. Accordingly, there can be no assurances that Select Energy will realize the gross margin corresponding to the present positive mark-to-market position on its wholesale marketing portfolios. The gross margin realized could be at a level that is not sufficient to cover Select Energy's other operating costs, including the cost of corporate overhead. Wholesale and retail marketing transactions, including the full requirements contracts, are intended to be part of Select Energy's normal purchases and sales and are recognized on the accrual basis of accounting. Hedging: Select Energy utilizes derivative financial and commodity instruments (derivatives), including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas sold under firm commitments. Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts, to manage the market risk associated with a portion of its anticipated supply requirements. These derivative instruments have been designated as cash flow hedging instruments. Cash flow hedges are recorded as assets or liabilities and included in accumulated other comprehensive income, which is a component of equity. These activities impact Select Energy's earnings when the forecasted hedged transaction is settled, when hedge ineffectiveness is measured and recorded, when the hedge is terminated and the forecasted transaction is expected to be break-even or less, or when the forecasted hedged transaction is no longer probable of occurring. During the third quarter of 2002, Select Energy determined that cash flow hedges related to the CL&P standard offer service contract were ineffective. In the third quarter, as a result of this ineffectiveness, Select Energy transferred $3.9 million from accumulated other comprehensive income to expense on the income statement related to these cash flow hedges. In September 2002, Select Energy terminated these cash flow hedges and realized pre-tax income of $5.6 million. Energy Trading: Select Energy's trading of energy contracts is accounted for using the mark-to-market method under EITF Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities." Energy trading transactions at Select Energy include financial transactions and physical delivery transactions for electricity, natural gas and oil in which Select Energy is attempting to profit from changes in market prices. For information regarding changes in accounting for energy trading transactions that will impact Select Energy in the future, see Note 1C, "New Accounting Standards," to the consolidated financial statements. As of September 30, 2002, Select Energy had unrealized gains on mark-to-market trading transactions of $135.1 million and unrealized losses on mark-to-market trading transactions of $53.4 million on a counterparty-by-counterparty basis, for a net positive position of $81.7 million on the entire trading portfolio. Additional information on the trading contract portfolio is included in the following tables. There can be no assurances that Select Energy will actually realize cash corresponding to the present positive net mark-to-market amount on its trading contracts. Numerous factors could either positively or negatively affect the realization in cash of the net mark-to-market amount. These include the volatility of commodity prices, changes in market design or settlement mechanisms, the outcome of future transactions, the performance of counterparties and other factors. Select Energy has policies and procedures requiring all trading positions to be marked-to-market at the end of each trading day. Controls are in place segregating responsibilities between individuals actually trading (front office) and those confirming the trades (middle office). The mark-to-market calculations are performed by individuals in the middle office independent from the front office. The methods used to mark-to-market energy trading contracts are identified and segregated in the table of fair value of contracts at September 30, 2002. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange futures and options that are marked to closing exchange prices; 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity or natural gas, and are marked to the mid-point of bid and ask quotes; and 3) prices based on models or other valuation methods primarily include forwards and options and other transactions for which specific quotes are not available. Long-term electric power prices are modeled using available information from external sources based on recent transactions and validated with a gas forward curve with an estimated heat rate conversion. Broker quotes are available through the year 2005, and models are used for the years 2006 and thereafter. Generally, valuations of short-term contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations based on models or other methods for longer-term contracts are less certain. Accordingly, there is a risk that contracts will not be realized at the amounts recorded. As of and for the three and nine months ended September 30, 2002, the sources of the fair value of trading contracts and the changes in fair value of these trading contracts are included in the following tables. Intercompany transactions are eliminated and not reflected in the amounts below. ------------------------------------------------------------------------------- (Millions of Dollars) Fair Value of Contracts at September 30, 2002 ------------------------------------------------------------------------------- Maturity Maturity of Maturity in Total Less than One to Four Excess of Fair Sources of Fair Value One Year Years Four Years Value ------------------------------------------------------------------------------- Prices actively quoted $ 1.8 $ 1.6 $ - $ 3.4 Prices provided by external sources 12.2 35.5 15.0 62.7 Prices based on models or other valuation methods - 7.0 8.6 15.6 ------------------------------------------------------------------------------- Totals $14.0 $44.1 $23.6 $81.7 ------------------------------------------------------------------------------- At June 30, 2002, the mark-to-market of trading contracts maturing in less than one year with prices based on models or other valuation methods was a negative $1.9 million. During the third quarter of 2002, prices from external sources became available to mark these contracts to market. These contracts are now valued at a positive $1.6 million. $2.5 million of the $3.5 million change in value is included in the following table as a change in fair value attributable to changes in valuation techniques and assumptions. Additionally, during the third quarter market information regarding certain long-term contracts with prices based on models or other valuation methods became available based on recent transactions. Select Energy used this market information in determining the estimated fair value of these contracts as of September 30, 2002. The result was a decrease in value of $4.1 million, which is also included in the following table as a change in fair value attributable to changes in valuation techniques and assumptions. The positive $2.5 million change and the negative $4.1 million change are reflected in the negative $1.6 million in the table below. The decrease in the number of counterparties participating in the market for long-term energy contracts continues to impact Select Energy's ability to determine the estimated value of its long-term energy contracts. ------------------------------------------------------------------------------- (Millions of Dollars) Total Fair Value ------------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30, 2002 September 30, 2002 ------------------------------------------------------------------------------- Fair value of contracts outstanding at the beginning of the period $75.5 $56.4 Contracts realized or otherwise settled during the period (5.0) (2.9) Fair value of new contracts when entered into during the period - 13.7 Changes in fair values attributable to changes in valuation techniques and assumptions (1.6) (6.0) Changes in fair value of contracts 12.8 20.5 ------------------------------------------------------------------------------- Fair value of contracts outstanding at the end of the period $81.7 $81.7 ------------------------------------------------------------------------------- During the first quarter of 2002, Select Energy terminated certain long-term energy contracts. Coincident with these contract terminations, new contracts were entered into with different terms and conditions. Select Energy also entered into other new contracts with existing counterparties. These new energy trading contracts are derivatives, and collectively they had a positive mark-to-market of $13.7 million when entered into and $14.8 million as of September 30, 2002. As indicated in the table above, the fair value of energy trading contracts increased $25.3 million from $56.4 million as of January 1, 2002 to $81.7 million as of September 30, 2002. This increase, which is more than offset by realized losses on positions taken and closed in 2002, is included in Select Energy's gross margin and included in the $16 million to $19 million the trading operations are expected to lose for 2002. Counterparty Credit: Counterparty credit risk relates to the risk of loss that Select Energy would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties' financial conditions (including credit ratings), collateral requirements under certain circumstances (including cash in advance, letters of credit, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to Select Energy entering into trading activities. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. As of September 30, 2002, approximately 70 percent of Select Energy's counterparty credit exposure to wholesale marketing and trading counterparties is cash collateralized or rated BBB- or better. More than two-thirds of the remaining credit exposure is to unrated municipalities. As of September 30, 2002, two counterparties collectively represented approximately 33 percent of the $135.1 million unrealized gains on mark-to- market transactions. Select Energy believes the risk associated with collecting amounts from these counterparties is minimal, primarily due to collateral balances or other security maintained. Select Energy Credit: A number of Select Energy's contracts require the posting of additional collateral in the form of cash or letters of credit in the event NU's ratings were to decline and in increasing amounts dependent upon the severity of the decline. At NU's present investment grade ratings, Select Energy has not had to post any collateral based on credit downgrades. Were NU's unsecured ratings to decline two to three notches to sub-investment grade, Select Energy would, under its present contracts, have to provide approximately $162 million of collateral to various counterparties, which NU, under present circumstances, would be able to provide Select Energy from available sources of funds. NU's ratings are currently stable, and management does not believe that at this time there is a significant risk of a ratings downgrade to sub-investment grade levels. Changing Market: The breadth and depth of the market for energy trading and marketing products in Select Energy's market has been adversely affected by the withdrawal or financial weakening of a number of companies who have historically done significant amounts of business with Select Energy. In general, the market for such products has become shorter term in nature, with less liquidity and participants less able to meet Select Energy's credit standards without providing cash or letter of credit support. Select Energy is being adversely affected by these factors, and there could be a continuing adverse impact on Select Energy's business prospects. Changes are occurring in the administration of transmission systems in territories in which Select Energy does business. Regional transmission organizations are being contemplated, and other changes are occurring within transmission regions. For example, the implementation of a standard market design in New England is expected to occur in 2003, and will create challenges and opportunities for Select Energy. The impact of standard market design implementation on Select Energy's existing positions cannot yet be determined but could have an adverse effect. For further information regarding Select Energy's activities and risks see Note 4, "Market Risk and Risk Management Instruments," and Note 6, "Comprehensive Income," to the consolidated financial statements. Business Development and Capital Expenditures NU's capital expenditures totaled $327.3 million in the first nine months of 2002, compared with $318 million in the first nine months of 2001. NU currently projects year end 2002 capital expenditures to approximate $500 million, approximately $100 million lower than the company had projected at the beginning of 2002. The primary reasons for the lower 2002 capital expenditure projection are delays in commencing work on high voltage electric transmission projects and lower projected capital spending at Yankee Gas. Those changes have been partially offset by increased capital expenditures for CL&P's electric distribution system. In 2001, CL&P announced plans for three high voltage transmission projects in southwestern Connecticut. The Connecticut Siting Council (CSC) approved the first project, replacement of an existing 138,000 volt line between Norwalk, Connecticut and Northport - Long Island, New York, in September 2002. Additional approvals are required from federal and New York state agencies. CL&P currently expects to complete the manufacture and installation of the cable in 2003 and early 2004, respectively. CL&P would share the $80 million cost of this project with the Long Island Power Authority (LIPA), which jointly owns the existing cable. As of September 30, 2002, CL&P has capitalized approximately $3.8 million related to this project. For the second project, CL&P proposed building a new 345,000 volt transmission line facility along an existing right-of-way between Norwalk, Connecticut and Bethel, Connecticut at an estimated cost of $135 million. The restart of CSC hearings on that project has been postponed until at least November 2002, and a decision is now expected in April 2003. As of September 30, 2002, CL&P has capitalized approximately $1.3 million related to this project. In May 2002, legislation was adopted in Connecticut authorizing a moratorium on the approval of additional electric and natural gas transmission crossings of Long Island Sound, which included a delay of decisions on the Bethel to Norwalk project and established task forces to study certain issues associated with siting electric and natural gas lines. As a result, no decision can be made by the CSC any earlier than February 1, 2003. The aforementioned CL&P-LIPA replacement cable is exempt from the moratorium. For the third project, CL&P announced plans for a separate $400 million 345,000 volt transmission line between Norwalk, Connecticut and Middletown, Connecticut. CL&P expects to apply to the CSC for approval of the project in 2003. As of September 30, 2002, CL&P has capitalized approximately $4.4 million related to this project. Merchant Energy Company Counterparty Exposures Certain subsidiaries of NU have entered into various transactions with subsidiaries of NRG Energy, Inc. (NRG). NRG's credit rating has been downgraded to below investment grade by all three major rating agencies, and is presently in default on debt service payments. CL&P - Standard Offer Supply: NRG's subsidiary, NRG Power Marketing, Inc. (NRG-PM), is under contract to supply a significant portion of CL&P's standard offer service requirement through December 31, 2003. NRG-PM is currently in default under the credit rating standards in the CL&P standard offer service contract. At the present time, CL&P has not terminated the contract for purposes of supply continuity, and NRG-PM continues to deliver standard offer supply service. CL&P continues to evaluate NRG-PM's ability to meet its obligations under the standard offer service contract. If NRG-PM ceases to deliver supply under the contract, CL&P would immediately seek alternate sources of energy to serve NRG-PM's portion of the standard offer service requirement. The price of this replacement supply could be greater than the current contract price. See below for management's discussion of the recovery of these costs from ratepayers. CL&P - Congestion Charges: Shortly after beginning to provide standard offer service to CL&P, NRG-PM ceased paying CL&P for congestion charges. In view of the deterioration of NRG-PM's financial condition, CL&P exercised its right of offset to withhold past due congestion costs from the July 2002 and subsequent standard offer payments to NRG-PM pending the outcome of litigation between the parties concerning contractual liability for congestion costs in the United States District Court for the District of Connecticut. See NU's 2001 Form 10-K, Item 3, "Legal Proceedings," for further information on this litigation. CL&P - Station Service: Under a Federal Energy Regulatory Commission (FERC) approved interconnection agreement with NRG, CL&P is providing station electric service to NRG's Connecticut subsidiaries at a standard retail rate. The NRG subsidiaries use this service when they are not generating at their plants. CL&P has been billing the NRG subsidiaries for this service since 2000. NRG has disputed and refused to pay all such billings, claiming that CL&P should not be utilizing a retail rate. Billings through September 30, 2002, amounted to approximately $12 million. CL&P has filed with the FERC to resolve this dispute. The outcome of this proceeding cannot be predicted, and management continues to evaluate the collectibility of the amounts in dispute as well as the financial condition of NRG and its subsidiaries. Yankee Gas: In 2002, both the Connecticut Department of Public Utility Control (DPUC) and the CSC approved construction of a natural gas pipeline and other gas distribution facilities by Yankee Gas to a 544 megawatt generating plant that Meriden Gas Turbines LLC (MGT), an NRG subsidiary, was constructing in Meriden, Connecticut. In October 2002, MGT notified Yankee Gas that it was permanently shutting down or abandoning construction of the generating plant. As a result, Yankee Gas immediately drew upon the full amount of a $16 million irrevocable letter of credit issued for the accounting of MGT. MGT has since disputed Yankee Gas's interpretation of the circumstances leading to the exercise of the irrevocable letter of credit and the appropriateness of the draw. Yankee Gas and MGT are currently discussing several options to address and remedy these contract disputes while preserving the project investment. Select Energy: Select Energy entered into certain energy trading contracts with NRG-PM. During the third quarter, Select Energy terminated those contracts as a result of failure to provide adequate financial assurances under those contracts by NRG-PM. In connection with the termination, Select Energy paid NRG-PM $3.1 million to close out the transactions. NRG-PM has disputed the amount owed and believes an additional $5.3 million is due. NGS: E.S. Boulos Company, a subsidiary of NGS, entered into a joint venture arrangement with an unaffiliated entity under which each party is a 50 percent owner. This joint venture is one of several subcontractors performing work on the generating plant that MGT was constructing. As discussed above, construction of this generating facility has been permanently shut down or abandoned. As a result of the situation and the uncertainty with respect to the completion of the plant, NGS has financial exposure of approximately $1.7 million related to collection of accounts receivable and settlements of other obligations. NGS is pursuing various options to minimize this financial exposure, including the filing of liens against the construction company and MGT. Management does not expect that the resolution of these disputes will have a material adverse effect on the NU's and its subsidiaries' financial condition or results of operations. Additionally, NU and its subsidiaries do not have a significant level of exposure to other merchant energy companies. Restructuring and Rate Matters Connecticut - CL&P: In 2002, 50 percent of CL&P's standard offer service requirements are served by Select Energy, 40 percent by NRG-PM and 10 percent by an affiliate of Duke Energy Corporation (Duke). In 2003, Select Energy will continue to serve 50 percent of CL&P's standard offer service requirements, but the percentage served by NRG-PM will rise to 45 percent, and the amount served by Duke will decline to 5 percent. As discussed above, CL&P continues to evaluate NRG-PM's ability to meet its obligations under the standard offer service contract. If CL&P is required to seek an alternate source of supply, CL&P would pursue recovery of any additional costs associated with obtaining such supply from NRG-PM pursuant to the contract and may be required to seek DPUC approval to flow through any such costs to customers. Management believes that recovery of these costs is consistent with the provisions of Connecticut's electric utility restructuring legislation and with the DPUC's prior decisions. On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale of the Millstone units to Dominion Nuclear Connecticut, Inc. (DNCI). This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale. The company hopes to receive a decision from the DPUC in 2002. On May 17, 2002, CL&P filed an application with the DPUC for the approval of the auction results in the sale of Seabrook to a subsidiary of FPL. The proceeds from the sale of Seabrook unit 1 will be utilized to offset stranded costs. Hearings were held in July 2002, and a final decision approving the sale was issued in September 2002. Connecticut - Yankee Gas: On October 1, 2002 Yankee Gas filed supplemental testimony and exhibits to its original Infrastructure Expansion Rate Mechanism (IERM) filing with the DPUC on August 1, 2002. This IERM filing reflected those 2001 through 2003 system expansion projects that Yankee Gas has undertaken or plans to undertake by June 30, 2003, and that meet certain financial criteria outlined by the DPUC. Yankee Gas is currently proposing no IERM charge for 2003, that current rates remain unchanged and that the projected 2003 revenue requirement be carried forward to the 2004 IERM period. A final decision from the DPUC regarding this filing is scheduled for the first quarter of 2003. New Hampshire: In July 2001, the New Hampshire Public Utilities Commission (NHPUC) opened a docket to review the fuel and purchased-power adjustment clause (FPPAC) costs incurred between August 2, 1999, and April 30, 2001. Hearings at the NHPUC concluded in June 2002, and PSNH filed its closing brief with the NHPUC in July 2002. Under the "Agreement to Settle PSNH Restructuring," FPPAC deferrals are recovered as a Part 3 stranded cost through the stranded cost recovery charge. Management believes the recoverability of these costs is probable and expects the NHPUC will issue its order by the end of 2002. On June 28, 2002, PSNH made its first stranded cost recovery charge reconciliation filing with the NHPUC for the period May 1, 2001, through December 31, 2001. This filing reconciles stranded cost revenues against actual stranded cost charges with any difference being recovered or deferred. Included in the stranded cost charges are the net generation revenues and generation costs for the filing period. Where generation revenues exceed costs, additional stranded costs were amortized; where generation costs exceed revenues, costs were deferred for future recovery. The generation costs included in this filing are subject to a prudence review by the NHPUC, and hearings have been scheduled for early 2003. Management does not expect this prudence review to have a material impact on PSNH's earnings. On September 12, 2002, the NHPUC issued a final decision approving the auction results in the sale of Seabrook to a subsidiary of FPL. On November 1, 2002, CL&P and NAEC consummated the sale of their 40.04 percent combined ownership interest in Seabrook to a subsidiary of FPL. CL&P, NAEC and certain other of the joint owners collectively sold 88.2 percent of Seabrook to FPL. Following the sale of NAEC's share of Seabrook, the proceeds received by NAEC, after NAEC repays its debt, will be refunded to PSNH through the Seabrook Power Contracts. PSNH will use the proceeds received from NAEC to recover stranded costs and repay debt with remaining amounts being available to be returned to NU. As part of the sale, FPL assumed responsibility for decommissioning Seabrook. Massachusetts: On March 30, 2001, WMECO filed its second annual stranded cost reconciliation with the DTE for calendar year 2000. On March 29, 2002, WMECO filed its 2001 annual transition cost reconciliation with the DTE. This filing reconciles the recovery of stranded generation costs for calendar year 2001 and includes sales proceeds from WMECO's portion of the Millstone units, the impact of securitization and approximately a $13 million benefit to ratepayers from WMECO's nuclear performance-based ratemaking process. On July 8, 2002, WMECO submitted a compliance filing in accordance with the DTE's June 7, 2002, order in WMECO's 1998 through 1999 stranded cost reconciliation proceedings. This filing reflected changes to the 1998 through 1999 reconciliations as agreed to by WMECO and/or ordered by the DTE and also included a revised transition charge filing for 2000 and 2001 to reflect the June 7, 2002 order. Subsequent to the July 8, 2002 filing, WMECO and the office of the Massachusetts Attorney General have participated in settlement discussions with regard to all transition charge issues for the 1998 through 2001 reconciliations. WMECO hopes to reach an agreement by the end of 2002. On July 1, 2002, WMECO completed a competitive bid process for a six-month contract from July 1, 2002 to December 31, 2002, to serve approximately 100 MW of WMECO default service. Affiliate Select Energy was the winner of the bid process and estimates that this contract will result in approximately $13.2 million of revenues in 2002. For further information regarding commitments and contingencies related to restructuring and rate matters, see Note 2A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements. Nuclear Plant Performance and Other Matters Seabrook: Seabrook operated at a capacity factor of 89 percent through the first nine months of 2002. Seabrook returned to service on June 1, 2002, after the completion of a 28-day scheduled refueling outage that began on May 4, 2002. Excluding the scheduled refueling outage, Seabrook operated at a capacity factor of 92 percent through the first nine months of 2002. On November 1, 2002, CL&P, NAEC, and certain other joint owners consummated the sale of their ownership interests in Seabrook to FPL. Other Matters Other Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 2, "Commitments and Contingencies," to the consolidated financial statements. Forward Looking Statements: This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancings, regulatory proceedings, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, and other presently unknown or unforeseen factors. RESULTS OF OPERATIONS The components of significant income statement variances for the third quarter of 2002 and the first nine months of 2002 are provided in the table below. The following table also includes the effects of the reclassification of trading revenues and expenses, which has been retroactively applied to all periods presented. For further information regarding this accounting change, see Note 1C, "New Accounting Standards," to the consolidated financial statements. Income Statement Variances (Millions of Dollars) 2002 over/(under) 2001 ----------------------------------- Third Nine Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $(169) (11)% $(900) (19)% Operating Expenses: Fuel, purchased and net interchange power (188) (19) (747) (26) Other operation (11) (5) (12) (2) Maintenance 9 14 (14) (7) Depreciation 5 11 (7) (5) Amortization 3 3 (690) (77) Taxes other than income taxes 8 20 6 4 Gain on sale of utility plant - - 644 100 ----- ---- ----- ---- Total operating expenses (174) (12) (820) (19) ----- ---- ----- ---- Operating income 5 4 (80) (20) ----- ---- ----- ---- Other income, net 14 81 (170) (90) Interest expense, net (2) (4) (5) (3) ----- ---- ----- ---- Income before income tax expense 21 36 (245) (63) Income tax expense 7 29 (124) (75) Preferred dividends of subsidiaries - - (2) (32) ----- ---- ----- ---- Income before cumulative effect of accounting change 14 40 (119) (56) ----- ---- ----- ---- Cumulative effect of accounting change, net of tax benefit - - 22 100 ----- ---- ----- ---- Net income $ 14 40% $ (97) (50)% ===== ==== ===== ==== Comparison of the Third Quarter of 2002 to the Third Quarter of 2001 Operating Revenues Total revenues decreased by $169 million or 11 percent in the third quarter of 2002, compared with the same period in 2001, primarily due to lower competitive energy revenues ($181 million, after intercompany eliminations), partially offset by higher regulated revenues ($11 million). The competitive energy companies' revenue decrease is primarily due to lower wholesale marketing revenues for Select Energy from full requirements contracts. The regulated revenue increase is primarily due to higher retail sales ($36 million), partially offset by lower revenue due to the net decrease in the WMECO standard offer energy rates ($21 million) and lower wholesale sales of energy and capacity ($10 million). Regulated retail electric kilowatt-hour (kWh) sales increased by 6.4 percent, and firm natural gas volume sales increased by 1.7 percent in the third quarter of 2002. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased in 2002, primarily due to lower costs of goods sold for wholesale marketing activities at the competitive businesses. Other Operation and Maintenance Other operation expense decreased $11 million in the third quarter of 2002, primarily due to lower competitive energy service companies' expenses associated with the costs of goods sold. Maintenance expense is higher due to higher transmission costs for the competitive companies due to increased load responsibilities. Depreciation Depreciation increased in 2002 due to higher regulated plant balances resulting from the recent level of construction expenditures. Taxes Other Than Income Taxes Taxes other than income taxes increased primarily due to the favorable 2001 property tax settlement with the City of Meriden which decreased the 2001 amount by $14 million, partially offset by the recognition in 2002 of a Connecticut sales and use tax audit settlement for the years 1993 through 2001 ($8 million). Other Income, Net Other income, net increased primarily due to the elimination of reserves associated with NU's ownership shares of Seabrook unit 2 in 2002 ($25 million), partially offset by the recording in 2001 of interest related to the City of Meriden property tax settlement ($6 million) and the 2001 recording of interest related to an income tax settlement ($6 million). Income Tax Expense Income tax expense increased due to higher taxable income. Comparison of the First Nine Months of 2002 to the First Nine Months of 2001 Operating Revenues Total revenues decreased by $900 million or 19 percent in the first nine months of 2002, compared with the same period in 2001, primarily due to lower competitive energy revenues ($497 million after intercompany eliminations), and lower regulated subsidiaries revenues due to lower wholesale revenues ($258 million), and lower regulated retail revenues ($145 million). The competitive energy companies' revenue decrease is primarily due to lower wholesale marketing revenues from Select Energy from full requirements contracts. The decrease in regulated wholesale revenues is due to lower PSNH wholesale sales ($77 million), the 2001 revenue associated with the sale of Millstone output ($42 million) and lower sales associated with other purchased-power contracts ($107 million). The regulated retail revenue decrease is due to rate decreases for PSNH and the decrease in the WMECO standard offer energy rate ($84 million), lower Yankee revenue due to a lower purchased gas adjustment clause rate ($61 million) and a combination of the rate decrease and lower gas sales ($28 million), partially offset by an increase for CL&P resulting from the collection of deferred fuel costs ($24 million) and higher retail electric sales ($5 million). Regulated retail electric kWh sales increased by 0.6 percent, and firm natural gas volume sales decreased by 7.9 percent in 2002. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased in 2002, primarily due to lower wholesale sales from the competitive businesses ($472 million) and lower purchased-power costs for the regulated subsidiaries ($274 million). Other Operation and Maintenance Other operation and maintenance (O&M) expenses decreased $26 million in 2002, primarily due to lower expenses associated with the regulated businesses ($48 million), partially offset by higher costs of goods sold for the competitive energy companies ($23 million). The regulated O&M decrease is primarily due to lower nuclear expenses as a result of the sale of the Millstone units at the end of the first quarter in 2001 ($48 million), lower distribution costs ($6 million), lower administration and general expenses ($6 million) and lower fossil and hydroelectric expenses ($2 million), partially offset by higher charges from the ISO for capacity, reliability and availability ($13 million). Depreciation Depreciation decreased in 2002 primarily due to the Millstone units decommissioning expenses recorded in 2001 ($7 million), lower NAEC expense due to the 2001 buydown which reduced plant balances ($3 million), lower Yankee expense resulting from lower depreciation allowed in the 2001 rate decision ($3 million), and lower competitive energy companies' expense resulting from generation assets life extensions ($1 million), partially offset by higher expense resulting from higher regulated balances ($7 million). Amortization Amortization decreased in 2002, primarily due to the amortization of the gain in 2001 related to the sale of the Millstone units ($644 million), higher amortization in 2001 related to recovery of the Millstone investment ($45 million) and the NAEC discontinuance of amortizing Seabrook deferred return in 2001 as a result of PSNH's restructuring ($16 million), partially offset by higher amortization related to the regulated companies' recovery of stranded costs ($15 million). Taxes Other Than Income Taxes Taxes other than income taxes increased primarily due to the favorable 2001 property tax settlement with the City of Meriden which decreased the 2001 amount by $14 million, partially offset by the recognition in 2002 of a Connecticut sales and use tax audit settlement for the years 1993 through 2001 ($8 million). Gain on Sale of Utility Plant In 2001, NU recorded gains on the sale of CL&P's and WMECO's ownership interests in the Millstone units. A corresponding amount of amortization expense was recorded. Other (Loss)/Income, Net Other (loss)/income, net decreased primarily due to NU's 2001 recognition of a gain in connection with the sale of Millstone units to DNCI ($202 million pre-tax), a 2002 charge reflecting a write-down in NU's investment in NEON ($15 million pre-tax), by the recording in 2001 of interest related to the City of Meriden property tax settlement ($6 million) and the 2001 recording of interest related to an income tax settlement ($6 million) and the gain on the disposition of property for PSNH in 2001 ($3 million), partially offset by a 2001 noncash charge related to the forward purchase of NU common shares ($35 million) and the elimination of reserves associated with NU's ownership shares of Seabrook unit 2 in 2002 ($25 million). Income Tax Expense Income tax expense decreased in 2002, primarily due to the recognition of WMECO investment tax credits in the second quarter of 2002 and the tax impacts of the Millstone sale in 2001. Cumulative Effect of Accounting Change, Net of Tax Benefit The cumulative effect of accounting change, net of tax benefit, recorded in 2001, represents the effect of the adoption of SFAS No. 133, as amended ($22 million). INDEPENDENT ACCOUNTANTS' REPORT To the Board of Trustees Northeast Utilities Berlin, Connecticut We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries ("the Company") as of September 30, 2002, and the related condensed consolidated statements of income for the three-month and nine-month periods then ended and the related condensed consolidated statement of cash flows for the nine-month period then ended. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to such condensed consolidated financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Hartford, Connecticut November 7, 2002 Northeast Utilities and Subsidiaries The Connecticut Light and Power Company and Subsidiaries Public Service Company of New Hampshire and Subsidiaries Western Massachusetts Electric Company and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies) A. Presentation The accompanying unaudited financial statements should be read in conjunction with the management's discussion and analysis of financial condition and results of operations in this Form 10-Q, the First and Second Quarter 2002 Form 10-Qs and the Annual Reports of Northeast Utilities (NU or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), which were filed as part of the NU 2001 Form 10-K, and the current reports on Form 8-K dated July 23, 2002, August 2, 2002, August 14, 2002, October 8, 2002, and October 21, 2002. The accompanying financial statements contain, in the opinion of management, all adjustments necessary to present fairly NU's and each NU system company's financial position as of September 30, 2002, the results of operations for the three-month and nine-month periods ended September 30, 2002 and 2001, and statements of cash flows for the nine-month periods ended September 30, 2002 and 2001. All adjustments are of a normal, recurring nature except those described in Notes 1C and 2. Due primarily to the seasonality of NU's business, the results of operations for the three-month and nine-month periods ended September 30, 2002 and 2001, and statements of cash flows for the nine-month periods ended September 30, 2002 and 2001, are not indicative of the results expected for a full year. The consolidated financial statements of NU and of its subsidiaries, as applicable, include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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 period data have been made to conform with the current period presentation. B. Regulatory Accounting and Assets The accounting policies of the NU system regulated operating companies conform to accounting principles generally accepted in the United States applicable to rate-regulated enterprises and reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." CL&P's, PSNH's and WMECO's transmission and distribution businesses continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 to those portions of those businesses continues to be appropriate. Management also believes it is probable that the NU system operating companies will recover their investments in long-lived assets, including regulatory assets. In addition, all material regulatory assets are earning a return, except for securitized regulatory assets. The components of the NU system companies' regulatory assets are as follows: --------------------------------------------------------------------- September 30, December 31, (Millions of Dollars) 2002 2001 --------------------------------------------------------------------- Recoverable nuclear costs $ 193.7 $ 231.6 Securitized regulatory assets 1,926.5 2,004.1 Income taxes, net 311.4 312.8 Unrecovered contractual obligations 70.3 78.3 Recoverable energy costs, net 307.6 327.2 Other 279.8 333.5 --------------------------------------------------------------------- Totals $3,089.3 $3,287.5 --------------------------------------------------------------------- C. New Accounting Standards Asset Retirement Obligations: In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires that legal obligations associated with the retirement of property, plant and equipment be recognized as a liability at fair value when incurred when a reasonable estimate of the fair value can be made. SFAS No. 143 is effective for NU's 2003 calendar year, and management is in the process of assessing the impact of SFAS No. 143 on NU's consolidated financial statements. Upon adoption of SFAS No. 143, there may be an impact on NU's consolidated financial statements which management has not determined at this time. Energy Trading and Risk Management Activities: In June 2002, the Emerging Issues Task Force (EITF) of the FASB reached a consensus on EITF Issue No. 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," requiring energy trading companies to classify revenues and expenses associated with certain energy trading contracts on a net basis within revenues, rather than recording the gross revenues and expenses. NU currently accounts for energy trading activities using the mark- to-market method under EITF Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities." EITF Issue No. 98-10 allows energy trading activities to be presented as revenues and as expenses or on a net basis in revenues in the statements of income. Effective July 1, 2002, NU adopted net reporting of revenues and expenses as allowed by EITF Issue No. 98-10. Prior to July 1, 2002, NU presented energy trading activities as revenues and expenses as allowed by EITF Issue No. 98-10. The adoption of net reporting was applied retroactively to all periods presented but will have no effect on net income. The three and nine months ended September 30, 2002, reflect net reporting. The revenues and expenses impacted relate to energy trading contracts that physically settle which were previously recorded as operating revenues for sales and fuel, purchased and net interchange power for the costs of the sales. The effects of this reporting for the three and nine months ended September 30, 2001, which have been previously reported, are as follows: --------------------------------------------------------------------- Competitive Energy NU Subsidiaries Consolidated --------------------------------------------------------------------- Three Nine Three Nine (Millions of Dollars) Months Months Months Months --------------------------------------------------------------------- Operating Revenues: As previously reported $777.2 $2,101.5 $1,723.9 $5,107.7 Impact of reclassification (193.2) (438.0) (193.2) (438.0) --------------------------------------------------------------------- As currently reported $584.0 $1,663.5 $1,530.7 $4,669.7 --------------------------------------------------------------------- --------------------------------------------------------------------- Competitive Energy NU Subsidiaries Consolidated --------------------------------------------------------------------- Three Nine Three Nine (Millions of Dollars) Months Months Months Months --------------------------------------------------------------------- Fuel, Purchased and Net Interchange Power: As previously reported $719.0 $1,863.8 $1,178.3 $3,318.9 Impact of reclassificaton (193.2) (438.0) (193.2) (438.0) --------------------------------------------------------------------- As currently reported $525.8 $1,425.8 $ 985.1 $2,880.9 --------------------------------------------------------------------- On October 25, 2002, the EITF reached additional consensuses in EITF Issue No. 02-3. These consensuses supercede the consensus the EITF reached in June 2002. The first consensus rescinds EITF Issue No. 98-10, under which Select Energy, Inc. (Select Energy) currently accounts for energy trading activities. The consensus will require energy trading companies to follow SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, for energy trading activities and to discontinue mark-to- market accounting for contracts that are not derivatives. Management is currently evaluating the extent of trading contracts that are not derivatives. The second consensus requires net reporting of derivative energy trading activities effective January 1, 2003. Management has already adopted net reporting of trading activities and will continue to evaluate EITF Issue No. 02-3 as additional guidance becomes available. D. Other (Loss)/Income, Net The components of NU's other (loss)/income, net items are as follows: --------------------------------------------------------------------- For the Nine Months Ended --------------------------------------------------------------------- September 30, September 30, (Millions of Dollars) 2002 2001 --------------------------------------------------------------------- Loss on investments $(17.1) $ - Gain related to Millstone sale - 201.9 Loss on share repurchase contracts - (35.4) Seabrook-related 23.3 - Other, net 13.5 24.1 --------------------------------------------------------------------- Totals $ 19.7 $190.6 --------------------------------------------------------------------- E. Change in Estimated Useful Lives In the second quarter of 2002, NU conducted studies of the depreciable lives of certain generation and software assets maintained by the competitive energy subsidiaries. The impact of these studies was to lengthen the useful lives of those generation assets by 20 years to an average of 58 remaining years and to shorten the useful lives of that software to 1.5 remaining years effective for the second quarter of 2002. As a result of these studies, NU's operating expenses decreased by approximately $3 million since the beginning of the second quarter of 2002. F. Sale of Customer Receivables As of September 30, 2002, CL&P had sold accounts receivable of $40 million to a subsidiary of Citigroup, Inc. with limited recourse through the CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. Additionally as of September 30, 2002, $4.2 million of assets were designated as collateral under the agreement with the CRC. Concentrations of credit risk to the purchaser under the this agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. 2. COMMITMENTS AND CONTINGENCIES A. Restructuring and Rate Matters (CL&P, PSNH, WMECO) Connecticut: On September 27, 2001, CL&P filed its application with the Connecticut Department of Public Utility Control (DPUC) for approval of the disposition of the proceeds in the amount of approximately $1.2 billion from the sale of the Millstone units to a subsidiary of Dominion Resources, Inc., Dominion Nuclear Connecticut, Inc. (DNCI). This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale. In accordance with Connecticut's electric utility industry restructuring legislation, CL&P was required to utilize any gains from the Millstone sale to offset stranded costs. There are certain contingencies related to this filing regarding the potential disallowance of what management believes were prudently incurred costs. Management believes the recoverability of these costs is probable. The company hopes to receive a decision from the DPUC in 2002. New Hampshire: In July 2001, the New Hampshire Public Utilities Commission (NHPUC) opened a docket to review the fuel and purchased- power adjustment clause (FPPAC) costs incurred between August 2, 1999, and April 30, 2001. Hearings at the NHPUC concluded in June 2002, and PSNH filed its closing brief with the NHPUC in July 2002. Under the "Agreement to Settle PSNH Restructuring," FPPAC deferrals are recovered as a Part 3 stranded cost through the stranded cost recovery charge. Management believes the recoverability of these costs is probable and expects the NHPUC will issue its order by the end of 2002. On June 28, 2002, PSNH made its first stranded cost recovery charge reconciliation filing with the NHPUC for the period May 1, 2001, through December 31, 2001. This filing reconciles stranded cost revenues against actual stranded cost charges with any difference being recovered or deferred. Included in the stranded cost charges are the net generation revenues and generation costs for the filing period. Where generation revenues exceed costs, additional stranded costs were amortized; where generation costs exceed revenues, costs were deferred for future recovery. The generation costs included in this filing are subject to a prudence review by the NHPUC, and hearings have been scheduled for early 2003. Management does not expect this prudence review to have a material impact on PSNH's earnings. Massachusetts: On March 30, 2001, WMECO filed its second annual stranded cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE) for calendar year 2000. On March 29, 2002, WMECO filed its 2001 annual transition cost reconciliation with the DTE. This filing reconciles the recovery of stranded generation costs for calendar year 2001 and includes sales proceeds from WMECO's portion of the Millstone units, the impact of securitization and approximately a $13 million benefit to ratepayers from WMECO's nuclear performance-based ratemaking process. On July 8, 2002, WMECO submitted a compliance filing in accordance with the DTE's June 7, 2002, order in WMECO's 1998 through 1999 stranded cost reconciliation proceedings. This filing reflected changes to the 1998 through 1999 reconciliations as agreed to by WMECO and/or ordered by the DTE and also included a revised transition charge filing for 2000 and 2001 to reflect the June 7, 2002 order. Subsequent to the July 8, 2002 filing, WMECO and the office of the Massachusetts Attorney General have participated in settlement discussions with regard to all transition charge issues for the 1998 through 2001 reconciliations. WMECO hopes to reach an agreement by the end of 2002. B. Long-Term Contractual Arrangements (Select Energy) Select Energy maintains long-term agreements to purchase energy in the normal course of business as part of its portfolio of resources to meet its actual or expected sales commitments. The aggregate amount of these purchase contracts was $4.3 billion at September 30, 2002. These contracts extend through 2006 as follows (millions of dollars): --------------------------------------------------------------------- Year --------------------------------------------------------------------- 2002 $1,496.5 2003 2,110.2 2004 405.4 2005 240.4 2006 68.4 --------------------------------------------------------------------- Total $4,320.9 --------------------------------------------------------------------- C. Other Investments Yankee Energy Services Company (YESCO), a subsidiary of Yankee Energy System, Inc. (Yankee), received a note receivable of $4.7 million from BMC Energy LLC (BMC Energy) in connection with the sale of certain renewable energy generation assets in 2001. On October 28, 2002, NU, on behalf of YESCO, delivered to BMC Energy a notice of an event of default with respect to the note. Under the terms of such note, BMC Energy has an obligation to provide certain financial information to determine the extent to which current cash flows are available to service the outstanding note balance of $4.7 million. If the event of default is not remedied by November 29, 2002, pursuant to the terms of note, all obligations will become immediately due and payable. YESCO is currently evaluating the recoverability of the note through either payments on the note or reacquisition of assets. 3. GOODWILL AND OTHER INTANGIBLE ASSETS Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other Intangible Assets," which ceases amortization of goodwill and certain intangible assets with indefinite useful lives. SFAS No. 142 also requires that goodwill and intangible assets deemed to have indefinite useful lives be reviewed for impairment upon adoption of SFAS No. 142 and at least annually thereafter by applying a fair value-based test. Under SFAS No. 142, goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit exceeds the carrying amount of the goodwill. In July 2002, the competitive energy subsidiaries acquired certain assets and assumed certain liabilities of Woods Electrical Co., Inc., an electrical services company and Woods Network Services, Inc., a telecommunications, construction and service company, for an aggregate purchase price of $15.3 million. The aggregate purchase price consisted of $3.3 million of tangible net assets, $0.5 million of intangible assets subject to amortization with a weighted average amortization period of 2.6 years, $5 million of intangible assets not subject to amortization, and $6.5 million of goodwill. This purchase price allocation is preliminary and subject to adjustment. Financial results of the acquired companies are included in NU's results of operations since July 1, 2002. The goodwill recognized in these transactions in the aggregate amount of $6.5 million was assigned to the competitive energy subsidiaries reportable segment and is expected to be fully deductible for tax purposes. Additionally, as part of these purchase agreements an additional payment of not more than $9.2 million would be contingently payable by 2005 if certain earnings targets are met. Any contingent payments made will be accounted for as part of the purchase price. Inclusive of the aforementioned acquisitions, as of September 30, 2002, NU maintains $319.4 million of goodwill that is no longer being amortized, $19.5 million of identifiable intangible assets which continue to be amortized over a period ranging from one to 15 years with a weighted average amortization period of 14.7 years and $5 million of intangible assets not subject to amortization. These amounts are included on the consolidated balance sheets as goodwill and other purchased intangible assets, net. NU's reporting units that maintain goodwill are generally consistent with the operating segments underlying the reportable segments identified in Note 8, "Segment Information," and are as follows: Yankee Gas Services Company (Yankee Gas), Select Energy Services, Inc. (SESI), Northeast Generation Services Company (NGS), NU Enterprises, Inc. (NUEI Parent), and YESCO. Yankee Gas is included in the regulated utilities - gas reportable segment and SESI, NGS, NUEI Parent, and YESCO are included in the competitive energy subsidiaries segment. The goodwill balances of these reporting units are included in the table below. NU has completed its initial impairment analysis for all reporting units that maintained goodwill upon adoption of SFAS No. 142 and has determined that no impairment exists. In completing this analysis, the fair values of the reporting units were estimated using both discounted cash flow methodologies and an analysis of comparable companies or transactions. A summary of NU's goodwill as of September 30, 2002, by reportable segment and reporting unit is as follows (millions of dollars): -------------------------------------------- Goodwill (Millions of Dollars) Balance -------------------------------------------- Regulated Utilities - Gas: Yankee Gas $287.6 Competitive Energy Subsidiaries: SESI 18.0 NGS 11.7 NUEI Parent 1.7 YESCO 0.4 -------------------------------------------- Total $319.4 -------------------------------------------- Except for the aforementioned acquisitions, there were no impairments or adjustments to these goodwill balances since January 1, 2002. As of September 30, 2002 and December 31, 2001, NU's intangible assets and related accumulated amortization consisted of the following: -------------------------------------------------------------------------- As of September 30, 2002 -------------------------------------------------------------------------- (Millions of Gross Accumulated Net Dollars) Balance Amortization Balance -------------------------------------------------------------------------- Intangible assets subject to amortization: Exclusivity agreement $17.7 $3.9 $13.8 Customer list 6.6 1.4 5.2 Employment related agreements and other 0.5 - 0.5 -------------------------------------------------------------------------- Totals $24.8 $5.3 $19.5 -------------------------------------------------------------------------- Intangible assets not subject to amortization: Customer relationships $ 2.0 Tradenames 3.0 -------------------------------------------------------------------------- Totals $ 5.0 -------------------------------------------------------------------------- -------------------------------------------------------------------------- As of December 31, 2001 -------------------------------------------------------------------------- (Millions of Gross Accumulated Net Dollars) Balance Amortization Balance -------------------------------------------------------------------------- Intangible assets subject to amortization: Exclusivity agreement $17.7 $3.1 $14.6 Customer list 6.6 1.1 5.5 -------------------------------------------------------------------------- Totals $24.3 $4.2 $20.1 -------------------------------------------------------------------------- NU recorded amortization expense of $1.1 million and $1.2 million during the first nine months of 2002 and 2001, respectively, related to these intangible assets. Based on the current amount of intangible assets subject to amortization, the estimated annual amortization expense for each of the succeeding 5 years from 2003 through 2007 is $1.8 million, $1.8 million, $1.7 million, $1.6 million, and $1.6 million, respectively. These amounts may vary as purchase price allocations are finalized and acquisitions and dispositions occur in the future. The results for the three months and nine months ended September 30, 2001, on a historical basis, do not reflect the provisions of SFAS No. 142. Had NU adopted SFAS No. 142 on January 1, 2001, historical net income and basic and fully diluted earnings per share (EPS) amounts would have been adjusted as follows: -------------------------------------------------------------------------- Fully (Millions of Dollars, except Net Basic Diluted share information) Income EPS EPS -------------------------------------------------------------------------- Three Months Ended September 30, 2001: -------------------------------------------------------------------------- Reported net income $34.6 $0.26 $0.26 Add back: goodwill amortization 2.3 0.02 0.02 -------------------------------------------------------------------------- Adjusted net income $36.9 $0.28 $0.28 -------------------------------------------------------------------------- Three Months Ended September 30, 2002: -------------------------------------------------------------------------- Reported net income $48.6 $0.38 $0.38 -------------------------------------------------------------------------- -------------------------------------------------------------------------- Fully (Millions of Dollars, except Net Basic Diluted share information) Income EPS EPS -------------------------------------------------------------------------- Nine Months Ended September 30, 2001: -------------------------------------------------------------------------- Reported net income $193.5 $1.41 $1.41 Add back: goodwill amortization 6.8 0.05 0.05 -------------------------------------------------------------------------- Adjusted net income $200.3 $1.46 $1.46 -------------------------------------------------------------------------- Nine Months Ended September 30, 2002: -------------------------------------------------------------------------- Reported net income $ 96.1 $0.74 $0.74 -------------------------------------------------------------------------- 4. MARKET RISK AND RISK MANAGEMENT INSTRUMENTS (NU, Select Energy, Yankee Gas) Derivative Instruments: Effective January 1, 2001, NU adopted SFAS No. 133, as amended. For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, the changes in the fair value of the effective portion of those contracts are recognized in accumulated other comprehensive income until the underlying transactions occur. For contracts that meet the definition of a derivative but do not meet the hedging requirements and for the ineffective portion of those that meet the hedging requirements, the changes in fair value of those contracts are recognized currently in earnings. Commodity derivatives that are utilized for trading purposes are currently accounted for using the mark-to-market method, under EITF Issue No. 98- 10, with changes in fair value included in earnings. For information regarding the rescission of EITF Issue No. 98-10, see Note 1C, "New Accounting Standards." There have been changes to interpretations of SFAS No. 133 and the FASB continues to consider changes and amendments which could affect the recording and disclosure of derivative and hedging activities. Competitive Energy Subsidiaries: Select Energy provides both full requirement energy services to its customers and engages in energy trading and marketing activities. Select Energy manages its exposure to risk from its contractual commitments and provides risk management services to its customers through forward contracts, futures, over-the- counter swap agreements, and options (commodity derivatives). Select Energy has utilized the sensitivity analysis methodology to disclose quantitative information for its commodity price risks. Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity prices, or other similar price changes. Commodity Price Risk - Trading Activities: As a market participant in the Northeast United States, Select Energy conducts commodity-trading activities in electricity and its related products, natural gas and oil, and therefore, experiences net open positions. Select Energy manages these open positions with strict policies which limit its exposure to market risk and require daily reporting to management of potential financial exposure. Under EITF Issue No. 98-10, these instruments are currently adjusted to market value, and the unrealized gains and losses are recognized in income in the current period in the consolidated statements of income in operating revenues, and in the consolidated balance sheets as unrealized gains and losses on mark-to-market transactions. The net mark-to-market positions at September 30, 2002 and December 31, 2001, were assets of $81.7 million and $56.4 million, respectively. Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity, contract prices and market prices represented by each derivative commodity contract. For swaps, forward contracts and options, market value reflects management's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recorded at market based on closing exchange prices. As of September 30, 2002, Select Energy has calculated the market price resulting from a 10 percent unfavorable change in forward market prices. That 10 percent change would result in approximately a $3.3 million decline in the fair value of the Select Energy trading portfolio. In the normal course of business, Select Energy also faces risks that are either nonfinancial or nonquantifiable. Such risks principally include credit risk, which is not reflected in this sensitivity analysis. Commodity Price Risk - Nontrading Derivative Activities: Select Energy utilizes derivative financial and commodity instruments (derivatives), including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas sold under firm commitments to certain customers. Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts, to manage the market risk associated with a portion of its anticipated supply requirements. These derivative instruments have been designated as cash flow hedging instruments. When conducting sensitivity analyses of the change in the fair value of Select Energy's electricity, natural gas and oil nontrading derivatives portfolio, which would result from a hypothetical change in the future market price of electricity, natural gas and oil, the fair values of the contracts are determined from models which take into account estimated future market prices of electricity, natural gas and oil, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments. In most instances, market prices and volatility are determined from quoted prices on the futures exchange. Select Energy has determined a hypothetical change in the fair value for its nontrading derivatives and electricity, natural gas and oil contracts, assuming a 10 percent unfavorable change in forward market prices. As of September 30, 2002, an unfavorable 10 percent change in market price would have resulted in a decline in fair value of approximately $15 million. The impact of a change in electricity, natural gas and oil prices on Select Energy's nontrading derivatives contracts on September 30, 2002, is not necessarily representative of the results that will be realized when these contracts are physically delivered. Select Energy also maintains natural gas service agreements with certain customers to supply gas at fixed prices for terms extending through 2004. Select Energy has hedged its gas supply risk under these agreements through New York Mercantile Exchange (NYMEX) contracts. Under these contracts, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements, which also extend through 2004. As of September 30, 2002, the NYMEX contracts had a notional value of $50.3 million and a mark-to-market asset value of $4.7 million. Regulated Entities: Commodity Price Risk - Nontrading Activities: Yankee Gas maintains a master swap agreement with a financial counterparty to purchase gas at fixed prices. Under this master swap agreement, the purchase price of a specified quantity of gas for two customers, an affiliate of the Rand- Whitney Group, Inc. and Kimberly Clark Corporation, is effectively fixed over the term of the gas service agreements with those customers for a period of time not extending beyond 2005. As of September 30, 2002, the commodity swap agreement had a notional value of $12.3 million and a mark-to-market asset value of $0.8 million, which is included in the $6.9 million reported for accumulated other comprehensive income related to hedging activities. Other Interest Rate and Credit Risk Activities: Interest Rate Risk - Nontrading Activities: NU manages its interest rate risk exposure by maintaining a mix of fixed and variable rate debt. As of September 30, 2002, approximately 79 percent of NU's long-term debt, including the current portion, is at a fixed interest rate. The remaining long-term debt is variable-rate and is subject to interest rate risk. Assuming a one percentage point increase in NU's variable interest rates, annual interest expense would have increased by $4.9 million. Credit Risk: Credit risk relates to the risk of loss that NU would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. NU serves a wide variety of customers and suppliers that include independent power producers, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and NU realizes interest receipts and payments related to balances outstanding in these accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms which, in turn, requires NU to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by NU's risk management process. Market risks at the competitive energy subsidiaries are monitored regularly by a Risk Oversight Council operating outside of the business units that create or actively manage these risk exposures to ensure compliance with NU's stated risk management policies. NU tracks and re-balances the risk in its portfolio in accordance with mark-to-market and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure. NYMEX traded futures and option contracts are guaranteed by the NYMEX and have a lower credit risk. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require an evaluation of potential counterparties' financial conditions (including credit ratings), collateral requirements under certain circumstances (including cash in advance, letters of credit, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to NU entering into trading activities. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact NU's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. 5. NUCLEAR GENERATION ASSETS DIVESTITURE (NU, CL&P, NAEC) In the third quarter of 2002, CL&P and North Atlantic Energy Corporation (NAEC) received regulatory approvals for the sale of Seabrook from the DPUC and the NHPUC. As a result of these approvals, CL&P and NAEC eliminated $0.6 million and $13.9 million, respectively, on an after-tax basis, of reserves related to their respective ownership shares of certain Seabrook assets. On November 1, 2002, CL&P and NAEC consummated the sale of their 40.04 percent combined ownership interest in Seabrook to a subsidiary of FPL Group, Inc. (FPL). CL&P, NAEC and certain other of the joint owners collectively sold 88.2 percent of Seabrook to FPL. The NU system received approximately $384 million of cash proceeds from the sale subject to certain true-up adjustments, and a portion of these proceeds were used to repay all $90 million of NAEC's outstanding debt, and will be used to return all NAEC's equity, which totaled $55.7 million as of September 30, 2002, to NU and pay between $90 million and $100 million in taxes. The remaining proceeds received by NAEC were refunded to PSNH through the Seabrook Power Contracts. As part of the sale, FPL assumed responsibility for decommissioning Seabrook. On October 10, 2000, NU reached an agreement with Baycorp Holdings, Ltd. (Baycorp), a 15 percent joint owner of Seabrook, under which NU guaranteed a minimum sale price and NU and Baycorp would share the excess proceeds if the sale of Seabrook resulted in proceeds of more than $87.2 million related to the sale of this 15 percent ownership interest. The agreement also limited any top-off amount required to be funded by Baycorp for decommissioning as part of the sale process. In connection with this agreement, NU received approximately $14 million in the fourth quarter of 2002. 6. COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO) Total comprehensive income, which includes all comprehensive income items, for the NU system is as follows: -------------------------------------------------------------------------- Nine Months Ended September 30, -------------------------------------------------------------------------- (Millions of Dollars) 2002 2001 -------------------------------------------------------------------------- NU consolidated $134.6 $158.8 CL&P 57.8 71.3 PSNH 45.8 63.4 WMECO 26.8 7.9 -------------------------------------------------------------------------- Accumulated other comprehensive income/(loss) mark-to-market adjustments of NU's qualified cash flow hedging instruments are as follows: -------------------------------------------------------------------------- (Millions of Dollars, Net of Tax) -------------------------------------------------------------------------- Balance at January 1, 2002 $(36.9) -------------------------------------------------------------------------- Hedged transactions recognized into earnings 19.5 Change in fair value 23.0 Cash flow transactions entered into for the period 1.3 -------------------------------------------------------------------------- Net change associated with the current period hedging transactions 43.8 ------------------------------------------------------------------------- Total mark-to-market adjustments included in accumulated other comprehensive income at September 30, 2002 $ 6.9 -------------------------------------------------------------------------- Accumulated other comprehensive income items unrelated to NU's qualified cash flow hedging instruments totaled $4.4 million in income and $0.8 million in losses as of January 1, 2002, and September 30, 2002, respectively. During the third quarter of 2002, Select Energy determined that cash flow hedges related to the CL&P standard offer service contract were ineffective. In the third quarter, as a result of this ineffectiveness, Select Energy transferred $3.9 million from accumulated other comprehensive income to expense on the income statement related to these cash flow hedges. In September 2002, Select Energy terminated these cash flow hedges and realized pre-tax income of $5.6 million. 7. EARNINGS PER SHARE (NU) EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if stock options granted under the NU Incentive Plan are converted into common stock. The following table sets forth the components of basic and fully diluted EPS: -------------------------------------------------------------------------- (Millions of Dollars, Nine Months Ended September 30, except share information) 2002 2001 -------------------------------------------------------------------------- Income before preferred dividends of subsidiaries $100.3 $222.1 Preferred dividends of subsidiaries 4.2 6.2 ------------------------------------------------------------------------- Income before cumulative effect of accounting change $ 96.1 $215.9 Cumulative effect of accounting change, net of tax benefit - (22.4) -------------------------------------------------------------------------- Net income $ 96.1 $193.5 -------------------------------------------------------------------------- Basic EPS common shares outstanding (average) 129,508,840 137,120,689 Dilutive effect of employee stock options 228,409 337,005 -------------------------------------------------------------------------- Fully diluted EPS common shares outstanding (average) 129,737,249 137,457,694 -------------------------------------------------------------------------- Basic and fully diluted EPS: Income before cumulative effect of accounting change $0.74 $1.57 Cumulative effect of accounting change, net of tax benefit - (0.16) -------------------------------------------------------------------------- Net income $0.74 $1.41 -------------------------------------------------------------------------- 8. SEGMENT INFORMATION (NU) The NU system is organized between regulated utilities (electric and gas) and competitive energy subsidiaries. The regulated utilities segment represents approximately 84 percent and 76 percent of the NU system's total revenues for the nine months ended September 30, 2002 and 2001, respectively, and is comprised of several business units. The reclassification of trading revenues and expenses, which has been retroactively applied to all periods presented, resulted in an increase in these percentages from amounts reported in prior periods. Regulated utilities revenues primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. In 2002, the competitive energy subsidiaries segment had one customer with revenues in excess of 10 percent of its total revenues, which was CL&P. The total purchases by CL&P represented approximately 43 percent of total competitive energy subsidiaries' revenues for the nine months ended September 30, 2002. In 2001, the total purchases by two customers, NSTAR and CL&P, represented approximately 15 percent and 30 percent, respectively, of total competitive energy subsidiaries' revenues for the nine months ended September 30, 2001. Total CL&P purchases from the competitive energy subsidiaries are eliminated in consolidation. The competitive energy subsidiaries segment in the following table includes SESI, a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional electric companies and electric utility companies; Holyoke Water Power Company, a company engaged in the production of electric power; Northeast Generation Company, a corporation that acquires and manages generation facilities; NGS, a corporation that maintains and services fossil or hydroelectric facilities and provides third-party electrical and engineering contracting services, and Select Energy, a corporation engaged in the trading, marketing, transportation, storage, and sale of energy commodities, at wholesale, in designated geographical areas and in the marketing of energy products to retail customers. Other in the following table includes the results for Mode 1 Communications, Inc., an investor in a fiber-optic communications network. Other also includes the results of the nonenergy related subsidiaries of Yankee. Interest expense included in Other primarily relates to the debt of NU parent. Inter-segment eliminations of revenues and expenses are also included in Other. ------------------------------------------------------------------------------- For the Three Months Ended September 30, 2002 ------------------------------------------------------------------------------- Regulated Utilities Competitive Eliminations (Millions of ------------------- Energy and Dollars) Electric Gas Subsidiaries Other Total ------------------------------------------------------------------------------- Operating revenues $1,106.2 $ 37.8 $ 396.0 $(179.0) $ 1,361.0 Operating expenses (975.0) (43.4) (397.8) 173.2 (1,243.0) ------------------------------------------------------------------------------- Operating income/ (loss) 131.2 (5.6) (1.8) (5.8) 118.0 Other income/ (loss), net 31.3 (0.5) 0.2 1.1 32.1 Interest expense, net (46.6) (3.5) (11.1) (6.5) (67.7) Income tax (expense)/ benefit (45.5) 3.8 3.7 5.6 (32.4) Preferred dividends (1.4) - - - (1.4) ------------------------------------------------------------------------------- Net income/ (loss) $ 69.0 $ (5.8) $ (9.0) $ (5.6) $ 48.6 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- For the Nine Months Ended September 30, 2002 ------------------------------------------------------------------------------- Regulated Utilities Competitive Eliminations (Millions of ------------------- Energy and Dollars) Electric Gas Subsidiaries Other Total ------------------------------------------------------------------------------- Operating revenues $2,962.6 $192.8 $1,107.3 $(492.6) $ 3,770.1 Operating expenses (2,620.0) (171.0) (1,133.8) 481.2 (3,443.6) ------------------------------------------------------------------------------- Operating income/ (loss) 342.6 21.8 (26.5) (11.4) 326.5 Other income/ (loss), net 33.4 (0.5) (3.0) (10.2) 19.7 Interest expense, net (140.5) (10.9) (32.9) (19.3) (203.6) Income tax (expense)/ benefit (79.0) (4.2) 22.5 18.4 (42.3) Preferred dividends (4.2) - - - (4.2) ------------------------------------------------------------------------------- Net income/ (loss) $ 152.3 $ 6.2 $ (39.9) $ (22.5) $ 96.1 ------------------------------------------------------------------------------- Total assets $7,973.7 $893.6 $1,854.5 $(405.6) $10,316.2 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- For the Three Months Ended September 30, 2001 ------------------------------------------------------------------------------- Regulated Utilities Competitive Eliminations (Millions of ------------------- Energy and Dollars) Electric Gas Subsidiaries Other Total ------------------------------------------------------------------------------- Operating revenues $1,083.9 $ 39.5 $ 584.0 $ (176.7) $ 1,530.7 Operating expenses (955.4) (34.7) (592.0) 164.8 (1,417.3) ------------------------------------------------------------------------------- Operating income/ (loss) 128.5 4.8 (8.0) (11.9) 113.4 Other income, net 5.0 3.8 2.1 6.8 17.7 Interest expense, net (53.5) (3.6) (9.2) (4.0) (70.3) Income tax (expense)/ benefit (35.5) (1.8) 5.4 6.7 (25.2) Preferred dividends (1.0) - - - (1.0) ------------------------------------------------------------------------------- Net income/ (loss) $ 43.5 $ 3.2 $ (9.7) $ (2.4) $ 34.6 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- For the Nine Months Ended September 30, 2001 ------------------------------------------------------------------------------- Regulated Utilities Competitive Eliminations (Millions of ------------------- Energy and Dollars) Electric Gas Subsidiaries Other Total ------------------------------------------------------------------------------- Operating revenues $3,284.0 $279.9 $1,663.5 $ (557.7) $ 4,669.7 Operating expenses (2,918.0) (248.5) (1,636.2) 539.4 (4,263.3) ------------------------------------------------------------------------------- Operating income/ (loss) 366.0 31.4 27.3 (18.3) 406.4 Other income, net 72.2 3.7 5.4 109.3 190.6 Interest expense, net (148.3) (10.6) (32.2) (17.9) (209.0) Income tax expense (129.2) (10.6) (0.9) (25.3) (166.0) Preferred dividends (6.1) - - - (6.1) ------------------------------------------------------------------------------- Income/(loss) before cumulative effect of accounting change 154.6 13.9 (0.4) 47.8 215.9 Cumulative effect of accounting change, net of tax benefit - - (22.0) (0.4) (22.4) ------------------------------------------------------------------------------- Net income/ (loss) $ 154.6 $ 13.9 $ (22.4) $ 47.4 $ 193.5 ------------------------------------------------------------------------------- Total assets $9,176.9 $867.6 $1,526.7 $(1,279.1) $10,292.1 ------------------------------------------------------------------------------- THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2002 2001 ---------------- ---------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash and cash equivalents............................ $ 7,827 $ 773 Investments in securitizable assets.................. 156,797 206,367 Notes receivable from affiliated companies........... 26,200 77,200 Receivables, net..................................... 92,840 77,801 Accounts receivable from affiliated companies........ 59,353 22,134 Unbilled revenues.................................... 4,380 7,492 Fuel, materials and supplies, at average cost........ 34,010 33,085 Prepayments and other................................ 26,295 17,703 ---------------- --------------- 407,702 442,555 ---------------- --------------- Property, Plant and Equipment: Electric utility..................................... 3,275,993 3,127,548 Less: Accumulated provision for depreciation...... 1,285,985 1,236,638 ---------------- --------------- 1,990,008 1,890,910 Construction work in progress........................ 129,038 134,964 Nuclear fuel, net.................................... 2,322 3,299 ---------------- --------------- 2,121,368 2,029,173 ---------------- --------------- Deferred Debits and Other Assets: Regulatory assets.................................... 1,734,386 1,877,191 Prepaid pension...................................... 272,198 233,692 Nuclear decommissioning trusts, at market............ 6,442 6,231 Other ............................................... 133,174 138,715 ---------------- --------------- 2,146,200 2,255,829 ---------------- --------------- Total Assets........................................... $ 4,675,270 $ 4,727,557 ================ ================ The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2002 2001 ---------------- ---------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Accounts payable...................................... $ 142,912 $ 132,593 Accounts payable to affiliated companies.............. 135,733 85,057 Accrued taxes......................................... 37,316 34,823 Accrued interest...................................... 10,149 10,369 Other................................................. 55,278 47,342 ---------------- ---------------- 381,388 310,184 ---------------- ---------------- Rate Reduction Bonds.................................... 1,271,834 1,358,653 ---------------- ---------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes..................... 752,537 820,444 Accumulated deferred investment tax credits........... 94,045 95,996 Deferred contractual obligations...................... 124,471 141,497 Other................................................. 368,415 283,399 ---------------- ---------------- 1,339,468 1,341,336 ---------------- ---------------- Capitalization: Long-Term Debt........................................ 827,071 824,349 ---------------- ---------------- Preferred Stock....................................... 116,200 116,200 ---------------- ---------------- Common Stockholder's Equity: Common stock, $10 par value - authorized 24,500,000 shares; 6,811,994 shares outstanding in 2002 and 7,584,884 shares outstanding in 2001... 68,120 75,849 Capital surplus, paid in............................ 369,794 414,018 Retained earnings................................... 301,775 286,901 Accumulated other comprehensive (loss)/income....... (380) 67 ---------------- ---------------- Common Stockholder's Equity........................... 739,309 776,835 ---------------- ---------------- Total Capitalization.................................... 1,682,580 1,717,384 ---------------- ---------------- Commitments and Contingencies (Note 2) Total Liabilities and Capitalization.................... $ 4,675,270 $ 4,727,557 ================ ================ The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, ------------------------------------------------- 2002 2001 2002 2001 ------------------------------------------------- (Thousands of Dollars) Operating Revenues.................................. $ 687,938 $ 675,578 $ 1,874,089 $ 2,019,758 --------- --------- ----------- ----------- Operating Expenses: Operation - Fuel, purchased and net interchange power...... 406,194 395,554 1,109,391 1,159,520 Other.......................................... 80,834 74,416 229,610 238,204 Maintenance....................................... 23,949 23,415 56,217 89,168 Depreciation...................................... 24,445 22,431 73,851 73,539 Amortization of regulatory assets, net............ 51,283 65,440 115,429 684,456 Taxes other than income taxes..................... 28,287 31,219 107,006 101,445 Gain on sale of utility plant..................... - - - (522,887) --------- --------- ----------- ----------- Total operating expenses........................ 614,992 612,475 1,691,504 1,823,445 --------- --------- ----------- ----------- Operating Income.................................... 72,946 63,103 182,585 196,313 Other Income, Net................................... 7,911 7,430 14,094 38,651 --------- --------- ----------- ----------- Income Before Interest and Income Tax Expense....... 80,857 70,533 196,679 234,964 --------- --------- ----------- ----------- Interest Expense: Interest on long-term debt........................ 10,844 12,357 33,177 48,141 Interest on rate reduction bonds.................. 18,789 20,224 57,273 40,801 Other interest.................................... 486 - (143) 984 --------- --------- ----------- ----------- Interest expense, net........................... 30,119 32,581 90,307 89,926 --------- --------- ----------- ----------- Income Before Income Tax Expense.................... 50,738 37,952 106,372 145,038 Income Tax Expense.................................. 21,441 19,128 43,984 69,102 --------- --------- ----------- ----------- Net Income.......................................... $ 29,297 $ 18,824 $ 62,388 $ 75,936 ========= ========= =========== =========== The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, ----------------------------------- 2002 2001 ---------------- ------------- (Thousands of Dollars) Operating Activities: Net income......................................................... $ 62,388 $ 75,936 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation..................................................... 73,851 73,539 Deferred income taxes and investment tax credits, net............ (59,570) (148,330) Net amortization/(deferral) of recoverable energy costs.......... 23,463 (5,923) Amortization of regulatory assets, net........................... 115,429 684,456 Gain on sale of utility plant.................................... - (522,887) Net other sources/(uses) of cash................................. 25,992 (90,652) Changes in working capital: Receivables and unbilled revenues, net........................... (49,146) 733 Fuel, materials and supplies..................................... (925) 2,497 Accounts payable................................................. 60,995 (2,452) Accrued taxes.................................................... 2,493 60,456 Investments in securitizable assets.............................. 49,570 (107,446) Other working capital (excludes cash)............................ (1,383) 47,886 -------------- -------------- Net cash flows provided by operating activities...................... 303,157 67,813 -------------- -------------- Investing Activities: Investments in plant: Electric utility plant........................................... (159,892) (167,068) Nuclear fuel..................................................... (54) (895) -------------- -------------- Cash flows used for investments in plant........................... (159,946) (167,963) Investment in NU system Money Pool................................. 51,000 (123,200) Investments in nuclear decommissioning trusts...................... (842) (95,494) Net proceeds from the sale of utility plant........................ - 827,691 Buyout/buydown of IPP contracts.................................... - (1,029,008) Other investment activities, net................................... 159 (97,233) -------------- -------------- Net cash flows used in investing activities.......................... (109,629) (685,207) -------------- -------------- Financing Activities: Repurchase of common shares........................................ (49,996) - Issuance of rate reduction bonds................................... - 1,438,400 Retirement of rate reduction bonds................................. (86,819) - Net decrease in short-term debt.................................... - (115,000) Reacquisitions and retirements of long-term debt................... - (416,000) Retirement of monthly income preferred securities.................. - (100,000) Retirement of capital lease obligation............................. - (145,800) Cash dividends on preferred stock.................................. (4,169) (4,169) Cash dividends on common stock..................................... (45,091) (45,054) Other financing activities, net.................................... (399) - -------------- -------------- Net cash flows (used in)/provided by financing activities............ (186,474) 612,377 -------------- -------------- Net increase/(decrease) in cash and cash equivalents................. 7,054 (5,017) Cash and cash equivalents - beginning of period...................... 773 5,461 -------------- -------------- Cash and cash equivalents - end of period............................ $ 7,827 $ 444 ============== ============== The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Financial Condition and Results of Operations CL&P is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management's discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2002 Form 10-Qs, current report on Form 8-K dated October 21, 2002, and the NU 2001 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the third quarter of 2002 and the first nine months of 2002 are provided in the table below. Income Statement Variances (Millions of Dollars) 2002 over/(under) 2001 ----------------------------------- Third Nine Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $12 2% $(146) (7)% Operating Expenses: Fuel, purchased and net interchange power 11 3 (50) (4) Other operation 6 9 (9) (4) Maintenance - - (33) (37) Depreciation 2 9 - - Amortization (14) (22) (569) (83) Taxes other than income taxes (3) (9) 6 5 Gain on sale of utility plant - - 523 100 --- --- ---- --- Total operating expenses 2 - (132) (7) --- --- ---- --- Operating income 10 16 (14) (7) Other income, net - - (25) (64) Interest expense, net (2) (8) - - --- --- ---- --- Income before income tax expense 12 34 (39) (27) Income tax expense 2 12 (25) (36) --- --- ---- --- Net income $10 56% $(14) (18)% === === ==== === Comparison of the Third Quarter of 2002 to the Third Quarter of 2001 Operating Revenues Operating revenues increased by $12 million or 2 percent in the third quarter of 2002, primarily due to higher retail revenues ($40 million), partially offset by lower wholesale revenues ($22 million). Retail revenues increased due to higher retail sales of 7.6 percent compared to the same period in 2001. Wholesale revenues were lower primarily due to lower sales of energy and capacity ($15 million), and lower revenue from market based contracts ($5 million). Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased in the third quarter of 2002, primarily due to the retail sales increase and the 2002 amortization of deferred fuel expenses. Other Operation Other operation expense increased by $6 million in the third quarter of 2002, primarily due to higher transmission expenses ($4 million) and higher administrative and general expenses ($2 million). Depreciation Depreciation expense increased in the third quarter of 2002 due to higher utility plant balances. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased in the third quarter of 2002 due to lower amortizations related to the recovery of stranded costs ($8 million), and lower amortization of the nuclear investment ($6 million). Taxes Other Than Income Taxes Taxes other than income taxes decreased in the third quarter of 2002 due to the recognition in 2002 of a Connecticut sales and use tax audit settlement for years 1993-2001 ($7 million), partially offset by the 2001 recognition of a property tax settlement with the City of Meriden. Interest Expense, Net Interest expense decreased in the third quarter of 2002, primarily due to the reacquisitions and retirements of long-term debt in 2001, and lower interest paid on rate reduction bonds. Income Tax Expense Income tax expense increased in the third quarter of 2002 due to higher book taxable income. Comparison of the First Nine Months of 2002 to the First Nine Months of 2001 Operating Revenues Operating revenues decreased by $146 million or 7 percent in 2002, primarily due to lower wholesale and other revenues ($183 million), partially offset by higher retail revenues ($37 million). Wholesale revenues were lower due to the sale of the Millstone units in the first quarter of 2001 ($62 million), lower revenues from sales of energy and capacity ($70 million) resulting from the buyout of cogenerator purchase contracts and lower wholesale market prices, and lower revenue from market based contracts ($24 million). Retail revenues were higher due to the recovery of previously deferred fuel costs ($24 million) and higher sales. Retail sales were 1.4 percent higher than last year. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased by $50 million in 2002, due to lower purchased-power costs resulting from the buydown and buyout of various cogeneration contracts ($46 million), lower market-based contracts ($20 million) and lower nuclear fuel expense ($7 million), partially offset by the 2002 amortization of deferred fuel expenses which are being recovered ($24 million). Other Operation and Maintenance Other O&M expense decreased by $42 million in 2002, primarily due to lower nuclear expenses as a result of the sale of the Millstone units at the end of the first quarter of 2001 ($51 million), partially offset by higher administrative and general expenses ($7 million). Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased in 2002, primarily due to higher amortization in 2001 related to the sale of the Millstone units ($523 million), lower amortization of the nuclear investment ($42 million), and lower amortizations related to the recovery of stranded costs ($2 million). Taxes Other Than Income Taxes Taxes other than income taxes increased in 2002, primarily due to the DPUC's order for CL&P to compensate the Town of Waterford for its loss of property tax revenue resulting from electric utility restructuring ($20 million), partially offset by the recognition of a Connecticut sales and use tax audit settlement for years 1993-2001 ($7 million), decreases in payroll taxes ($3 million) and local property taxes ($2 million). CL&P is recovering through rates the additional property tax payments to the Town of Waterford. Gain on Sale of Utility Plant In 2001, CL&P recorded a gain on the sale of its ownership share in the Millstone units. A corresponding amount of amortization expense was recorded. Other Income, Net Other income, net decreased in 2002, primarily due to the gain recognized in 2001 on the sale of the Millstone units ($29 million). Income Tax Expense Income tax expense decreased in 2002 primarily due to lower book taxable income. LIQUIDITY CL&P expects its cash position to further improve in the fourth quarter of 2002 due to the sale of CL&P's 4.06 percent share of Seabrook on November 1, 2002. The net gain from the sale related to CL&P's share of Seabrook primarily will be used to offset stranded costs, and the cash proceeds received by CL&P will be used to meet its capital requirements. CL&P had no significant financing activity in the third quarter 2002. In November 2002, NU expects to decrease to $300 million from $350 million a line of credit for its regulated subsidiaries, including CL&P. CL&P did not have any borrowings outstanding under this facility as of September 30, 2002. CL&P projects a modest level of system financings over the next three months to six months. CL&P is currently contemplating the issuance of up to $200 million of debt to refinance its prior spent nuclear fuel obligations pursuant to the Nuclear Waste Policy Act of 1982 for nuclear fuel burned prior to April 6, 1983. CL&P's net cash flows provided by operating activities increased to $303.2 million in the first nine months of 2002, compared with net cash flows provided by operating activities of $67.8 million during the same period of 2001. Cash flows provided by operating activities increased primarily due to taxes payable in 2001 in connection with the sale of the Millstone units. Also contributing to the increase is the amortization of recoverable energy costs in 2002 compared with deferrals in 2001. Changes in working capital items also contributed to the increase. There was a lower level of investing and financing activities in the first nine months of 2002, as compared to the same period of 2001, primarily due to the sale of the Millstone units, the buyout and buydown of independent power producer contracts, and the issuance rate reduction certificates in 2001. The level of common dividends totaled $45.1 million in the first nine months of 2002 and 2001. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2002 2001 ---------------- ---------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash................................................. $ 718 $ 1,479 Receivables, net..................................... 79,037 70,540 Accounts receivable from affiliated companies........ 178 13,055 Unbilled revenues.................................... 26,153 29,268 Fuel, materials and supplies, at average cost........ 40,527 42,047 Prepayments and other................................ 18,187 10,211 ---------------- ---------------- 164,800 166,600 ---------------- ---------------- Property, Plant and Equipment: Electric utility..................................... 1,500,101 1,447,955 Other................................................ 6,221 6,221 ---------------- ---------------- 1,506,322 1,454,176 Less: Accumulated provision for depreciation...... 710,125 689,397 ---------------- ---------------- 796,197 764,779 Construction work in progress........................ 47,731 44,961 ---------------- ---------------- 843,928 809,740 ---------------- ---------------- Deferred Debits and Other Assets: Regulatory assets.................................... 1,012,804 1,046,760 Other ............................................... 97,208 71,414 ---------------- ---------------- 1,110,012 1,118,174 ---------------- ---------------- Total Assets........................................... $ 2,118,740 $ 2,094,514 ================ ================ The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2002 2001 ---------------- ---------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to banks................................ $ 55,000 $ 60,500 Notes payable to affiliated companies................. 17,200 23,000 Obligations under Seabrook Power Contracts and other capital leases - current portion.......... 19,347 24,164 Accounts payable...................................... 35,571 32,285 Accounts payable to affiliated companies.............. 360 18,727 Accrued taxes......................................... 27,244 2,281 Accrued interest...................................... 14,684 9,428 Overcollections on rate reduction bonds............... 25,310 12,479 Other................................................. 14,569 12,685 ---------------- ---------------- 209,285 195,549 ---------------- ---------------- Rate Reduction Bonds.................................... 518,654 507,381 ---------------- ---------------- Obligations under Seabrook Power Contracts and Other Capital Leases.............................. 77,043 86,111 ---------------- ---------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes..................... 421,212 423,050 Accumulated deferred investment tax credits........... 5,014 12,015 Deferred contractual obligations...................... 33,829 37,712 Accrued pension....................................... 37,580 37,326 Other................................................. 45,925 46,260 ---------------- ---------------- 543,560 556,363 ---------------- ---------------- Capitalization: Long-Term Debt........................................ 407,285 407,285 ---------------- ---------------- Common Stockholder's Equity: Common stock, $1 par value - authorized 100,000,000 shares; 388 shares outstanding in 2002 and 2001................................... - - Capital surplus, paid in............................ 164,093 165,000 Retained earnings................................... 199,044 176,419 Accumulated other comprehensive (loss)/income....... (224) 406 ---------------- ---------------- Common Stockholder's Equity........................... 362,913 341,825 ---------------- ---------------- Total Capitalization.................................... 770,198 749,110 ---------------- ---------------- Commitments and Contingencies (Note 2) Total Liabilities and Capitalization.................... $ 2,118,740 $ 2,094,514 ================ ================ The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, ------------------------------------------------ 2002 2001 2002 2001 ------------------------------------------------ (Thousands of Dollars) Operating Revenues................................ $ 324,818 $ 299,711 $ 816,113 $ 927,345 --------- --------- --------- --------- Operating Expenses: Operation - Fuel, purchased and net interchange power.... 190,152 166,889 460,575 585,652 Other........................................ 33,309 31,102 94,315 95,097 Maintenance..................................... 13,342 12,165 45,585 46,959 Depreciation.................................... 10,377 8,199 30,681 30,009 Amortization of regulatory assets, net.......... 27,813 26,676 49,271 39,581 Taxes other than income taxes................... 8,896 9,117 27,003 30,255 --------- --------- --------- --------- Total operating expenses...................... 283,889 254,148 707,430 827,553 --------- --------- --------- --------- Operating Income.................................. 40,929 45,563 108,683 99,792 Other Income/(Loss), Net.......................... 231 538 (887) 39,026 --------- --------- --------- --------- Income Before Interest and Income Tax Expense..... 41,160 46,101 107,796 138,818 --------- --------- --------- --------- Interest Expense: Interest on long-term debt...................... 4,127 7,383 13,554 22,398 Interest on rate reduction bonds................ 7,584 7,932 23,022 13,266 Other interest.................................. 390 135 291 (52) --------- --------- --------- --------- Interest expense, net......................... 12,101 15,450 36,867 35,612 --------- --------- --------- --------- Income Before Income Tax Expense.................. 29,059 30,651 70,929 103,206 Income Tax Expense................................ 9,577 9,021 24,487 37,697 --------- --------- --------- --------- Net Income........................................ $ 19,482 $ 21,630 $ 46,442 $ 65,509 ========= ========= ========= ========= The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, ----------------------------- 2002 2001 ------------ ------------ (Thousands of Dollars) Operating activities: Net income.......................................................... $ 46,442 $ 65,509 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation...................................................... 30,681 30,009 Deferred income taxes and investment tax credits, net............. (17,446) 184,001 Net amortization/(deferral) of recoverable energy costs........... 12,494 (32,010) Amortization of regulatory assets, net............................ 49,271 39,581 Gain on sale of utility plant..................................... - (25,924) Net other (uses)/sources of cash.................................. (30,058) (30,010) Changes in working capital: Receivables and unbilled revenues, net............................ 7,496 1,870 Fuel, materials and supplies...................................... 1,520 (7,906) Accounts payable.................................................. (15,081) 10,984 Accrued taxes..................................................... 24,963 141,248 Taxes receivable.................................................. - (177,590) Other working capital (excludes cash)............................. 11,365 27,362 ------------ ------------ Net cash flows provided by operating activities....................... 121,647 227,124 ------------ ------------ Investing Activities: Investments in plant: Electric utility plant............................................ (75,817) (65,438) Nuclear fuel...................................................... - (37) ------------ ------------ Cash flows used for investments in plant............................ (75,817) (65,475) Investment in NU system Money Pool.................................. (5,800) 27,000 Investments in nuclear decommissioning trusts....................... - (1,625) Net proceeds from sale of utility plant............................. - 24,888 Other investment activities, net.................................... (8,179) (32,661) ------------ ------------ Net cash flows used in investing activities........................... (89,796) (47,873) ------------ ------------ Financing Activities: Repurchase of common shares......................................... - (260,000) Issuance of rate reduction bonds.................................... 50,000 525,000 Retirement of rate reduction bonds.................................. (38,727) - Net decrease in short-term debt..................................... (5,500) - Reacquisitions and retirements of preferred stock................... - (24,268) Buydown of capital lease obligation................................. - (497,508) Cash dividends on preferred stock................................... - (1,929) Cash dividends on common stock...................................... (24,500) (27,000) Other financing activities, net..................................... (13,885) - ------------ ------------ Net cash flows used in financing activities........................... (32,612) (285,705) ------------ ------------ Net decrease in cash.................................................. (761) (106,454) Cash - beginning of period............................................ 1,479 115,135 ------------ ------------ Cash - end of period.................................................. $ 718 $ 8,681 ============ ============ The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES Management's Discussion and Analysis of Financial Condition and Results of Operations PSNH is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management's discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2002 Form 10-Qs, current report on Form 8-K dated October 21, 2002, and the NU 2001 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the third quarter of 2002 and the first nine months of 2002 are provided in the table below. Income Statement Variances (Millions of Dollars) 2002 over/(under) 2001 ----------------------------------- Third Nine Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $25 8% $(111) (12)% Operating Expenses: Fuel, purchased and net interchange power 23 14 (125) (21) Other operation 2 7 (1) (1) Maintenance 1 10 (1) (3) Depreciation 2 27 1 2 Amortization of regulatory assets, net 1 4 9 24 Taxes other than income taxes - - (3) (11) --- --- ---- --- Total operating expenses 29 12 (120) (15) --- --- ---- --- Operating income (4) (10) 9 9 --- --- ---- --- Other income, net - - (40) (a) Interest expense, net (3) (22) 1 4 --- --- ---- --- Income before income tax expense (1) (5) (32) (31) Income tax expense 1 6 (13) (35) --- --- ---- --- Net income $(2) (10)% $(19) (29)% === === ==== === (a) Percent greater than 100. Comparison of the Third Quarter of 2002 to the Third Quarter of 2001 Operating Revenues Total operating revenues increased $25 million or 8 percent in the third quarter of 2002 compared with the same period of 2001, primarily due to higher wholesale revenues from sales of capacity and energy primarily due to a reduction in prices and a lower volume of bilateral transactions and sales of excess capacity and energy ($15 million) and higher retail revenues ($10 million) due to higher retail sales. Retail kilowatt-hour (kWh) sales increased by 4.5 percent in the third quarter of 2002. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased in 2002, primarily due to higher wholesale and retail sales. Other Operation and Maintenance Other O&M expense increased $3 million in 2002, primarily due to higher maintenance costs associated with the generating plants ($2 million) and higher administrative and general costs ($1 million). Depreciation Depreciation increased in 2002, primarily due to the new Energy Park facility. Interest Expense Interest expense decreased $3 million in 2002, primarily due to the December 2001 refinancing of long-term debt at lower rates. Comparison of the First Nine Months of 2002 to the First Nine Months of 2001 Operating Revenues Total operating revenues decreased $111 million or 12 percent in the first nine months 2002 compared with the same period of 2001, primarily due to lower retail revenues ($35 million) and lower wholesale revenues from sales of capacity and energy ($77 million) primarily due to a reduction in prices and a lower volume of bilateral transactions and sales of excess capacity and energy. Retail revenues decreased primarily due to a rate decrease on May 1, 2001 ($25 million) and lower retail sales ($10 million). Retail kWh sales decreased by 1.7 percent in 2002. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased $125 million or 21 percent in 2002, primarily due to lower wholesale and retail sales. Other Operation and Maintenance Other O&M expense decreased ($2 million) in 2002, primarily due to lower operating costs for the fossil plants ($2 million) and lower nuclear expense ($2 million), which were partially offset by higher transmission and dispatch costs ($2 million). Amortization of Regulatory Assets, Net Amortization of regulatory assets, net increased in 2002, due to higher amortizations resulting from restructuring in 2001. Taxes Other than Income Taxes Taxes other than income taxes decreased $3 million in 2002, primarily due to lower New Hampshire franchise taxes. Other Income, Net Other income, net decreased in 2002, primarily due to the sale of Millstone 3 in 2001 ($26 million), a gain on the disposition of property in 2001 ($4 million) and lower interest and dividend income in 2002 ($3 million). Interest Expense Interest expense increased in 2002, primarily due the issuance of rate reduction bonds in April 2001 and January 2002, partially offset by the December 2001 refinancing of long-term debt at lower rates. Income Tax Expense Income tax expense decreased in 2002, primarily due to the sale of Millstone 3 in 2001. LIQUIDITY PSNH expects its cash position to further improve in the fourth quarter of 2002 due to the sale of NAEC's 35.98 percent share of Seabrook on November 1, 2002. Following the sale of NAEC's share of Seabrook, PSNH will use the proceeds refunded from NAEC to recover stranded costs and repay approximately $60 million of debt with any remaining amounts being available to be returned to NU. PSNH had no significant financing activity in the third quarter of 2002. In November 2002, NU expects to decrease to $300 million from $350 million a line of credit for its regulated subsidiaries, including PSNH. As of September 30, 2002, PSNH had $55 million outstanding under this facility. PSNH's net cash flows provided by operating activities decreased to $121.6 million in the first nine months of 2002, compared with $227.1 million during the same period of 2001. Cash flows provided by operating activities decreased primarily due to the tax impact related to the buydown of the Seabrook Power Contracts during 2001. Additionally, cash flows provided by operating activities decreased as a result of a $19.1 million decrease in net income in 2002. These decreases were partially offset by higher net amortization of recoverable energy costs in 2002 as compared to net deferrals in 2001. There was a lower level of investing and financing activities in the first nine months of 2002, as compared to the same period of 2001, primarily due to the issuance of rate reduction bonds and the buydown of the Seabrook Power Contracts in 2001. In 2002, PSNH issued $50 million of rate reduction bonds. The level of common dividends totaled $24.5 million in the first nine months of 2002 and $27 million in the first nine months of 2001. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2002 2001 ---------------- ---------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash................................................. $ 1 $ 599 Receivables, net..................................... 42,156 43,761 Accounts receivable from affiliated companies........ 32 2,208 Unbilled revenues.................................... 6,756 12,746 Fuel, materials and supplies, at average cost........ 1,689 1,457 Prepayments and other................................ 1,063 1,544 ---------------- ---------------- 51,697 62,315 ---------------- ---------------- Property, Plant and Equipment: Electric utility..................................... 585,608 564,857 Less: Accumulated provision for depreciation...... 194,461 186,784 ---------------- ---------------- 391,147 378,073 Construction work in progress........................ 9,851 18,326 ---------------- ---------------- 400,998 396,399 ---------------- ---------------- Deferred Debits and Other Assets: Regulatory assets.................................... 275,907 320,222 Prepaid pension...................................... 64,490 54,226 Other ............................................... 18,328 19,500 ---------------- ---------------- 358,725 393,948 ---------------- ---------------- Total Assets........................................... $ 811,420 $ 852,662 ================ ================ The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2002 2001 ---------------- ---------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to banks................................ $ 55,000 $ 50,000 Notes payable to affiliated companies................. 29,700 9,200 Accounts payable...................................... 13,573 34,970 Accounts payable to affiliated companies.............. 540 2,982 Accrued taxes......................................... 4,780 3,691 Accrued interest...................................... 1,369 2,201 Other................................................. 12,641 10,127 ---------------- ---------------- 117,603 113,171 ---------------- ---------------- Rate Reduction Bonds.................................... 144,980 152,317 ---------------- ---------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes..................... 226,725 229,893 Accumulated deferred investment tax credits........... 3,746 3,998 Deferred contractual obligations...................... 32,817 37,357 Other................................................. 32,424 64,309 ---------------- ---------------- 295,712 335,557 ---------------- ---------------- Capitalization: Long-Term Debt........................................ 101,805 101,170 ---------------- ---------------- Common Stockholder's Equity: Common stock, $25 par value - authorized 1,072,471 shares; 434,653 shares outstanding in 2002 and 509,696 shares outstanding in 2001..... 10,866 12,742 Capital surplus, paid in............................ 69,774 82,224 Retained earnings................................... 70,739 55,422 Accumulated other comprehensive (loss)/income....... (59) 59 ---------------- ---------------- Common Stockholder's Equity........................... 151,320 150,447 ---------------- ---------------- Total Capitalization.................................... 253,125 251,617 ---------------- ---------------- Commitments and Contingencies (Note 2) Total Liabilities and Capitalization.................... $ 811,420 $ 852,662 ================ ================ The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, -------------------------------------------------- 2002 2001 2002 2001 -------------------------------------------------- (Thousands of Dollars) Operating Revenues.................................... $ 95,684 $ 120,679 $ 278,880 $ 370,845 ---------- ---------- ---------- ---------- Operating Expenses: Operation - Fuel, purchased and net interchange power........ 46,927 75,803 140,510 245,254 Other............................................ 12,516 20,740 37,083 50,761 Maintenance......................................... 3,798 3,575 10,029 16,124 Depreciation........................................ 3,415 3,124 11,038 10,675 Amortization of regulatory assets, net.............. 14,281 180 33,357 125,590 Taxes other than income taxes....................... 2,223 2,436 7,966 10,360 Gain on sale of utility plant....................... - - - (121,022) ---------- ---------- ---------- ---------- Total operating expenses...................... 83,160 105,858 239,983 337,742 ---------- ---------- ---------- ---------- Operating Income...................................... 12,524 14,821 38,897 33,103 Other Income/(Loss), Net.............................. 742 (3,074) (2,342) (3,764) ---------- ---------- ---------- ---------- Income Before Interest Expense and Income Tax Expense/(Benefit)........................ 13,266 11,747 36,555 29,339 ---------- ---------- ---------- ---------- Interest Expense: Interest on long-term debt.......................... 806 814 2,417 4,520 Interest on rate reduction bonds.................... 2,379 2,727 7,245 3,636 Other interest...................................... 616 599 1,132 3,264 ---------- ---------- ---------- ---------- Interest expense, net............................ 3,801 4,140 10,794 11,420 ---------- ---------- ---------- ---------- Income Before Income Tax Expense/(Benefit)............ 9,465 7,607 25,761 17,919 Income Tax Expense/(Benefit).......................... 4,735 3,727 (1,181) 9,202 ---------- ---------- ---------- ---------- Net Income............................................ $ 4,730 $ 3,880 $ 26,942 $ 8,717 ========== ========== ========== ========== The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, ------------------------------ 2002 2001 ------------ ------------- (Thousands of Dollars) Operating Activities: Net income........................................................ $ 26,942 $ 8,717 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation.................................................... 11,038 10,675 Deferred income taxes and investment tax credits, net........... (19,312) 13,626 Net amortization of recoverable energy costs.................... 322 3,548 Amortization of regulatory assets, net.......................... 33,357 125,590 Gain on sale of utility plant................................... - (121,022) Net other (uses)/sources of cash................................ (20,510) 13,411 Changes in working capital: Receivables and unbilled revenues, net.......................... 9,771 10,547 Fuel, materials and supplies.................................... (232) 80 Accounts payable................................................ (23,839) 23,298 Accrued taxes................................................... 1,089 (8,164) Other working capital (excludes cash)........................... 2,039 (968) ------------ ------------- Net cash flows provided by operating activities..................... 20,665 79,338 ------------ ------------- Investing Activities: Investments in plant: Electric utility plant.......................................... (14,739) (23,957) Nuclear fuel.................................................... - (140) ------------ ------------- Cash flows used for investments in plant.......................... (14,739) (24,097) Investment in NU system Money Pool................................ 20,500 50,100 Investments in nuclear decommissioning trusts..................... - (21,767) Net proceeds from the sale of utility plant....................... - 175,154 Buyout of IPP contract............................................ - (99,700) Other investment activities, net.................................. 1,334 (3,557) ------------ ------------- Net cash flows provided by investing activities..................... 7,095 76,133 ------------ ------------- Financing Activities: Repurchase of common shares....................................... (13,999) (15,000) Issuance of rate reduction bonds.................................. - 155,000 Retirement of rate reduction bonds................................ (7,337) - Net increase/(decrease) in short-term debt........................ 5,000 (110,000) Reacquisitions and retirements of long-term debt.................. - (100,000) Reacquisitions and retirements of preferred stock................. - (36,500) Retirement of capital lease obligation............................ - (34,200) Cash dividends on preferred stock................................. - (690) Cash dividends on common stock.................................... (12,005) (8,998) Other financing activities, net................................... (17) - ------------ ------------- Net cash flows used in financing activities......................... (28,358) (150,388) ------------ ------------- Net (decrease)/increase in cash..................................... (598) 5,083 Cash - beginning of period.......................................... 599 985 ------------ ------------- Cash - end of period................................................ $ 1 $ 6,068 ============ ============= The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY Management's Discussion and Analysis of Financial Condition and Results of Operations WMECO is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management's discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the First and Second Quarter 2002 Form 10-Qs, current report on Form 8-K dated October 21, 2002, and the NU 2001 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the third quarter of 2002 and the first nine months of 2002 are provided in the table below. Income Statement Variances (Millions of Dollars) 2002 over/(under) 2001 ----------------------------------- Third Nine Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $(25) (21)% $ (92) (25)% Operating Expenses: Fuel, purchased and net interchange power (29) (38) (105) (43) Other operation (8) (40) (14) (27) Maintenance - - (6) (38) Depreciation - - - - Amortization 14 (a) (92) (73) Taxes other than income taxes - - (2) (23) Gain on sale of utility plant - - 121 100 ---- --- ----- --- Total operating expenses (23) (21) (98) (29) ---- --- ----- --- Operating income (2) (15) 6 18 ---- --- ----- --- Other income, net 4 (a) 1 38 Interest expense, net - - (1) (5) ---- --- ----- --- Income before income tax expense 2 24 8 44 Income tax expense 1 27 (10) (a) ---- --- ----- --- Net income $ 1 22% $ 18 (a)% ==== === ===== === (a) Percent greater than 100. Comparison of the Third Quarter of 2002 to the Third Quarter of 2001 Operating Revenues Operating revenues decreased by $25 million or 21 percent in 2002, primarily due to lower retail revenues ($21 million) and lower wholesale and other revenues ($4 million). Retail revenues were lower primarily due to a decrease in the standard offer service rate resulting from a competitive bid process required by the DTE ($30 million) partially offset by an increase in the transition charge rate ($9 million) and higher distribution revenues from higher sales. The decrease in revenues related to the decrease in the standard offer service rate is offset by a corresponding decrease in fuel, purchased and net interchange power. Retail sales increased by 5.3 percent. Wholesale revenues were lower primarily due to the expiring of long-term contracts ($2 million). Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased in 2002, primarily due to the lower supply price for standard offer service ($29 million). Amortization of Regulatory Assets, Net Amortization of regulatory assets, net increased in the third quarter of 2002 primarily due to higher amortizations related to the recovery of stranded costs ($12 million). Other Operation Other operation expense decreased by $8 million in 2002 primarily due to a one-time pension charge in 2001 ($6 million). Other Income, Net Other income, net increased in 2002, primarily due to environmental costs recorded in 2001. Comparison of the First Nine Months of 2002 to the First Nine Months of 2001 Operating Revenues Operating revenues decreased by $92 million or 25 percent in 2002, primarily due to lower retail revenues ($57 million) and lower wholesale and other revenues ($35 million). Retail revenues were lower primarily due to a decrease in the standard offer service rate resulting from a competitive bid process required by the DTE ($84 million) partially offset by an increase in the transition charge rate ($23 million) and higher distribution revenues. The decrease in revenues related to the decrease in the standard offer service rate is offset by a corresponding decrease in fuel, purchased and net interchange power. Retail sales increased by 0.8 percent. Wholesale revenues were lower primarily due to lower sales of energy and capacity due to buydown and buyout of various cogenerator contracts ($13 million), the inclusion in 2001 of revenue from the output of the Millstone units ($14 million) and lower sales of Vermont Yankee ($4 million). The buydown and buyout of cogeneration contracts has a corresponding decrease in fuel, purchased and net interchange power. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased in 2002, primarily due to the lower supply price for standard offer service ($85 million), the buydown and buyout of various cogeneration contracts ($12 million) and lower nuclear fuel expense ($4 million). Other Operation and Maintenance Other O&M expense decreased by $19 million in 2002, primarily due to lack of nuclear expenses in 2002 as a result of the sale of Millstone units at the end of the first quarter in 2001 ($12 million) and lower general and administrative expenses ($6 million). Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased in 2002 ($92 million) primarily due to the amortization in 2001 related to the sale of the Millstone units ($121 million) offset by higher amortizations in 2002 related to the recovery of stranded costs ($31 million). Gain on Sale of Utility Plant In 2001, WMECO recorded a gain on the sale of its ownership share in the Millstone units. A corresponding amount of amortization expense was recorded. Income Tax Expense Income tax expense decreased in 2002 primarily due to the recognition in 2002 of investment tax credits as a result of a regulatory decision ($13 million). LIQUIDITY WMECO had no significant financing activities in the third quarter of 2002. In November 2002, NU expects to decrease to $300 million from $350 million a line of credit for its regulated subsidiaries, including WMECO. As of September 30, 2002, WMECO had $55 million outstanding under this facility. WMECO projects a modest level of system financings over the next three months to six months. WMECO has applied to the DTE to issue $100 million of debt to refinance existing short-term debt and its prior spent nuclear fuel obligations pursuant to the Nuclear Waste Policy Act of 1982 for nuclear fuel burned prior to April 6, 1983. WMECO's net cash flows provided by operating activities decreased to $20.7 million in the first nine months of 2002, compared with $79.3 million during the same period of 2001. Changes in working capital items were the primary drivers of the decrease. There was a lower level of investing and financing activities in the first nine months of 2002, as compared to the same period of 2001, primarily due to the sale of the Millstone units, the buyout and buydown of independent power producer contracts, and the issuance of rate reduction certificates in 2001. The level of common dividends totaled $12 million in the first nine months of 2002 and $9 million in the first nine months of 2001. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The quantitative and qualitative disclosures about market risk are set forth in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," herein. ITEM 4. CONTROLS AND PROCEDURES NU, CL&P, PSNH and WMECO (collectively, the companies) evaluated the design and operation of their disclosure controls and procedures to determine whether they are effective in ensuring that the disclosure of required information is timely made in accordance with the Exchange Act and the rules and forms of the Securities and Exchange Commission (SEC). These evaluations were made under the supervision and with the participation of management, including the companies' principal executive officer and principal financial officer, within the 90-day period prior to the filing of this Quarterly Report on Form 10-Q. The principal executive officer and principal financial officer have concluded, based on their review, that the companies' disclosure controls and procedures, as defined at Exchange Act Rules 13a-14(c) and 15(d)- 14(c), are effective to ensure that information required to be disclosed by the companies in reports that it files under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. No significant changes were made to the companies' internal controls or other factors that could significantly affect these controls subsequent to the date of their evaluation. PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS 1. Bridgeport Energy, LLC v. Northeast Utilities Service Company and Select Energy, Inc. In July 2001, Select Energy filed a lawsuit against Bridgeport Energy, LLC (Bridgeport) (a subsidiary of Duke Energy) in Connecticut Superior Court regarding termination of a July 1998 contract to purchase installed capability (ICAP) from Bridgeport. The contract, which had been assigned to Select Energy by Holyoke Power and Electric Company, contained a termination clause allowing either party to terminate if the Federal Energy Regulatory Commission (FERC), NEPOOL or the Independent System Operator - New England (ISO - New England) either eliminated ICAP or made material changes to ICAP which affected the parties and such changes could not be resolved through negotiation. Select Energy sought to terminate the contract under the termination clause after ISO - New England filed with FERC to eliminate the ICAP product. Bridgeport filed a lawsuit shortly thereafter alleging Select Energy was in default under the contract and requesting damages for the remainder of the contract. The complaints have been transferred to the complex litigation docket of the court with a scheduling order contemplating a trial in October 2003. The parties are engaged in discovery. Select Energy has also requested that the court strike the portion of Bridgeport's complaint alleging that Select Energy engaged in unfair trade practices under Connecticut law. Bridgeport has scheduled a series of depositions of Northeast Utilities Service Company (NUSCO) and Select Energy personnel to be completed by December 6, 2002. Non-binding mediation occurred on October 17, 2002, but no settlement has been reached. 2. Millstone Station - Damage to Fish Population Lawsuits On April 26, 2000, a lawsuit was filed in Hartford Superior Court naming as defendants the Commissioner of the Connecticut Department of Environmental Protection (DEP), Northeast Nuclear Energy Company (NNECO) and NUSCO. This lawsuit, brought by the Connecticut Coalition Against Millstone (CCAM), the Long Island Coalition Against Millstone, The Connecticut Green Party, Don't Waste Connecticut and the STAR Foundation, challenged the validity of previously issued DEP emergency and temporary authorizations allowing Millstone to discharge wastewater not expressly authorized by the facility's water discharge National Pollutant Discharge Elimination System Permit (NPDES Permit). On October 16, 2000, this matter was dismissed by the Superior Court. The plaintiffs filed an appeal of the dismissal with the Connecticut Appellate Court. On June 26, 2002, the Appellate Court granted NUSCO's motion to dismiss the appeal as moot. On August 6, 2002, CCAM moved to reopen this appeal with the Appellate Court. CCAM's motion was denied on September 11, 2002, and CCAM has requested the Connecticut Supreme Court to hear an appeal of the Appellate Court decision. 3. Sale of Millstone to Dominion Nuclear Connecticut, Inc. In March 2001, CCAM filed suit against the DEP, NNECO and DNCI challenging the validity of Millstone's NPDES Permit and a previously issued DEP emergency authorization allowing Millstone to discharge wastewater not expressly authorized by the facility's NPDES Permit. The suit also challenged DEP's authority to transfer both Millstone's NPDES Permit and emergency authorization to DNCI. In July 2001, this matter was dismissed by the Connecticut Superior Court and in August 2001, CCAM filed an appeal with the Connecticut Appellate Court. On September 20, 2002, the Connecticut Supreme Court assigned the matter to itself. The suit has not yet been scheduled for oral argument. 4. Federal Energy Regulatory Commission - Installed Capability Deficiency Charge In July 2001, NU filed an appeal of the FERC orders imposing a $0.17 per kilowatt-month ICAP charge from August 1, 2000 to April 1, 2001. In December 2001, FERC denied rehearing of its order allowing the $0.17 rate during the court-imposed stay period, April through August 2001. NU appealed this decision to the First Circuit Court of Appeals (First Circuit) and on October 4, 2002, the First Circuit denied the appeal. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Listing of Exhibits (NU) Exhibit No. Description ----------- ----------- 10.38.4 Arrangement with Respect to Seabrook 10.38.5 Employment Agreement with Michael Morris dated as of August 20, 2002 15 Deloitte & Touche LLP Letter Regarding Unaudited Financial Information 99.1 Certification of Michael G. Morris, Chairman, President and Chief Executive Officer of Northeast Utilities and John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2002 (a) Listing of Exhibits (CL&P) 4.2.7.4 Amendment No. 2 to the Standby Bond Purchase Agreement dated as of September 9, 2002, among CL&P, The Bank of New York, and the Participating Banks referred to therein 99.1 Certification of Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power Company (the Company) and John H. Forsgren, Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company, as Agent for the Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002, dated November 7, 2002 (a) Listing of Exhibits (PSNH) 99.1 Certification of Cheryl W. Grise, Chief Executive Officer of Public Service Company of New Hampshire (the Company) and John H. Forsgren, Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company, as Agent for the Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2002 (a) Listing of Exhibits (WMECO) 99.1 Certification of Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric Company (the Company) and John H. Forsgren, Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company, as Agent for the Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002, dated November 7, 2002 (b) Reports on Form 8-K: NU filed a current report on Form 8-K dated July 23, 2002, disclosing: o NU's earnings press release for the second quarter and six months ended June 30, 2002. NU filed a current report on Form 8-K dated August 2, 2002, disclosing: o NU's submission to the SEC of certain Statements under Oath of the Principal Executive Officer and Principal Financial Officer in accordance with the SEC's June 27, 2002 Order requiring the filing of sworn statements pursuant to Section 21(a)(1) of the Securities and Exchange Act of 1934. NU filed a current report on Form 8-K dated August 14, 2002, disclosing: o NU's submission to the SEC of certain Statements under Oath of the Principal Executive Officer and Principal Financial Officer in accordance with the SEC's June 27, 2002 Order requiring the filing of sworn statements pursuant to Section 21(a)(1) of the Securities and Exchange Act of 1934. NU filed a current report on Form 8-K dated October 8, 2002, disclosing: o NU's announcement of the lowering of its 2002 earnings guidance and the declaration of a regular common dividend. NU filed a current report on Form 8-K dated October 21, 2002, disclosing: o NU's earnings press release for the third quarter and nine months ended September 30, 2002. NU, CL&P, PSNH, and WMECO filed current reports on Form 8-K dated October 21, 2002, disclosing: o Presentation information related to earnings guidance for 2002 and 2003. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. NORTHEAST UTILITIES ------------------- Registrant Date: November 7, 2002 By /s/ John H. Forsgren ---------------- -------------------------------------- John H. Forsgren Vice Chairman, Executive Vice President and Chief Financial Officer Date: November 7, 2002 By /s/ John P. Stack ---------------- -------------------------------------- John P. Stack Vice President - Accounting and Controller CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Michael G. Morris, Chairman, President and Chief Executive Officer of Northeast Utilities (the Company), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 7, 2002 /s/ Michael G. Morris (Signature) Michael G. Morris Chairman, President and Chief Executive Officer CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities (the Company), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 7, 2002 /s/ John H. Forsgren (Signature) John H. Forsgren Vice Chairman, Executive Vice President and Chief Financial Officer SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. THE CONNECTICUT LIGHT AND POWER COMPANY --------------------------------------- Registrant Date: November 7, 2002 By /s/ Randy A. Shoop ---------------- -------------------------------------- Randy A. Shoop Treasurer Date: November 7, 2002 By /s/ John P. Stack ---------------- -------------------------------------- John P. Stack Vice President - Accounting and Controller CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power Company (the Company), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 7, 2002 /s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John H. Forsgren, Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company as Agent for The Connecticut Light and Power Company (the Company), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 7, 2002 /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company, as Agent for the Company SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE --------------------------------------- Registrant Date: November 7, 2002 By /s/ David R. McHale ---------------- -------------------------------------- David R. McHale Vice President and Treasurer Date: November 7, 2002 By /s/ John P. Stack ---------------- -------------------------------------- John P. Stack Vice President - Accounting and Controller CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Cheryl W. Grise, Chief Executive Officer of Public Service Company of New Hampshire (the Company), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 7, 2002 /s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John H. Forsgren, Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company as Agent for Public Service Company of New Hampshire (the Company), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 7, 2002 /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company, as Agent for the Company SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. WESTERN MASSACHUSETTS ELECTRIC COMPANY -------------------------------------- Registrant Date: November 7, 2002 By /s/ David R. McHale ---------------- -------------------------------------- David R. McHale Vice President and Treasurer Date: November 7, 2002 By /s/ John P. Stack ---------------- -------------------------------------- John P. Stack Vice President - Accounting and Controller CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric Company (the Company), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 7, 2002 /s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John H. Forsgren, Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company as Agent for Western Massachusetts Electric Company (the Company), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the Evaluation Date); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 7, 2002 /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company, as Agent for the Company