10-Q 1 march2003v5.txt FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2003 -------------- 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 by check mark whether the registrants are accelerated filers (as defined in Rule 12b-2 of the Exchange Act): 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 April 30, 2003 ------------------------ ----------------------------- Northeast Utilities Common shares, $5.00 par value 126,638,593 shares The Connecticut Light and Power Company Common stock, $10.00 par value 6,035,205 shares Public Service Company of New Hampshire Common stock, $1.00 par value 301 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 Citigroup.................. Citigroup, Inc. CL&P....................... The Connecticut Light and Power Company CRC........................ CL&P Receivables Corporation CVEC....................... Connecticut Valley Electric Company HWP........................ Holyoke Water Power Company NAEC....................... North Atlantic Energy Corporation NEON....................... NEON Communications, Inc. NGC........................ Northeast Generation Company NGS........................ Northeast Generation Services Company NRG........................ NRG Energy, Inc. NRG-PM..................... NRG Power Marketing, Inc. NU or the company.......... Northeast Utilities NU Enterprises............. NU's competitive subsidiaries comprised of Select Energy, NGC, SESI, NGS, HWP, and Woods Network. For further information, see Note 7, "Segment Information," to the consolidated financial statements. 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. Utility Group.............. NU's regulated utilities comprised of CL&P, PSNH, WMECO, NAEC and Yankee Gas. For further information, see Note 7, "Segment Information," to the consolidated financial statements. WMECO...................... Western Massachusetts Electric Company Woods Network.............. Woods Network Services, Inc. Yankee..................... Yankee Energy System, Inc. Yankee Gas................. Yankee Gas Services Company REGULATORS DPUC....................... Connecticut Department of Public Utility Control DTE........................ Massachusetts Department of Telecommunications and Energy FERC....................... Federal Energy Regulatory Commission NHPUC...................... New Hampshire Public Utilities Commission SEC........................ Securities and Exchange Commission OTHER ABO........................ Accumulated Benefit Obligation ARO........................ Asset Retirement Obligation CSC........................ Connecticut Siting Council CTA........................ Competitive Transition Assessment EAC........................ Energy Adjustment Clause EITF....................... Emerging Issues Task Force EPS........................ Earnings per Share FASB....................... Financial Accounting Standards Board FIN........................ FASB Interpretation GSC........................ Generation Services Charge IPPs....................... Independent Power Producers ISO-NE..................... New England Independent System Operator kWh........................ Kilowatt-hour LMP........................ Locational Marginal Pricing MW......................... Megawatts NU 2002 Form 10-K.......... The Northeast Utilities and Subsidiaries combined 2002 Form 10-K as filed with the SEC NYMEX...................... New York Mercantile Exchange O&M........................ Operation and Maintenance Restructuring Settlement............... Agreement to Settle PSNH Restructuring RMR........................ Reliability Must Run SMD........................ Standard Market Design TS......................... Transition Service 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 - March 31, 2003 and December 31, 2002................... 2 Consolidated Statements of Income - Three Months Ended March 31, 2003 and 2002............. 4 Consolidated Statements of Cash Flows - Three Months Ended March 31, 2003 and 2002............. 5 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 6 Independent Accountants' Report............................. 25 Notes to Consolidated Financial Statements (unaudited - all companies).................................. 26 The Connecticut Light and Power Company and Subsidiaries Consolidated Balance Sheets - March 31, 2003 and December 31, 2002................... 46 Consolidated Statements of Income - Three Months Ended March 31, 2003 and 2002............. 48 Consolidated Statements of Cash Flows - Three Months Ended March 31, 2003 and 2002............. 49 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 50 Public Service Company of New Hampshire and Subsidiaries Consolidated Balance Sheets - March 31, 2003 and December 31, 2002................... 54 Consolidated Statements of Income - Three Months Ended March 31, 2003 and 2002............. 56 Consolidated Statements of Cash Flows - Three Months Ended March 31, 2003 and 2002............. 57 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 58 Western Massachusetts Electric Company and Subsidiary Consolidated Balance Sheets - March 31, 2003 and December 31, 2002................... 62 Consolidated Statements of Income - Three Months Ended March 31, 2003 and 2002............. 64 Consolidated Statements of Cash Flows - Three Months Ended March 31, 2003 and 2002............. 65 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 66 Item 3. Quantitative and Qualitative Disclosures About Market Risk.......................... 68 Item 4. Controls and Procedures................................ 68 Part II. Other Information Item 1. Legal Proceedings...................................... 69 Item 6. Exhibits and Reports on Form 8-K....................... 69 Signatures and Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002..................................... 71 NORTHEAST UTILITIES AND SUBSIDIARIES NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2003 2002 --------------- ------------ (Thousands of Dollars) ASSETS ------ Current Assets: Cash and cash equivalents................................... $ 98,959 $ 54,678 Investments in securitizable assets......................... 155,759 178,908 Receivables, net............................................ 702,669 767,089 Unbilled revenues........................................... 116,092 126,236 Fuel, materials and supplies, at average cost............... 111,230 119,853 Special deposits............................................ 84,038 43,261 Derivative assets........................................... 198,448 130,929 Prepayments and other....................................... 95,077 110,261 ----------- ----------- 1,562,272 1,531,215 ----------- ----------- Property, Plant and Equipment: Electric utility............................................ 5,211,492 5,141,951 Gas utility................................................. 690,988 679,055 Competitive energy.......................................... 864,661 866,294 Other....................................................... 205,878 205,115 ----------- ----------- 6,973,019 6,892,415 Less: Accumulated depreciation............................ 2,516,514 2,484,613 ----------- ----------- 4,456,505 4,407,802 Construction work in progress............................... 322,429 320,567 ----------- ----------- 4,778,934 4,728,369 ----------- ----------- Deferred Debits and Other Assets: Regulatory assets .......................................... 2,833,150 2,909,923 Goodwill and other purchased intangible assets, net......... 344,965 345,867 Prepaid pension............................................. 336,540 328,890 Other ...................................................... 417,342 433,444 ----------- ----------- 3,931,997 4,018,124 ----------- ----------- Total Assets................................................. $10,273,203 $10,277,708 =========== =========== The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2003 2002 --------------- --------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to banks...................................... $ 95,000 $ 56,000 Long-term debt - current portion............................ 55,749 56,906 Accounts payable............................................ 687,735 776,219 Accrued taxes............................................... 84,759 141,667 Accrued interest............................................ 56,889 40,597 Derivative liabilities...................................... 125,620 63,900 Other....................................................... 203,909 208,680 ----------- ----------- 1,309,661 1,343,969 ----------- ----------- Rate Reduction Bonds.......................................... 1,856,411 1,899,312 ----------- ----------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes........................... 1,414,993 1,436,507 Accumulated deferred investment tax credits................. 105,517 106,471 Deferred contractual obligations............................ 346,830 354,469 Other....................................................... 569,595 523,115 ----------- ----------- 2,436,935 2,420,562 ----------- ----------- Capitalization: Long-Term Debt.............................................. 2,324,432 2,287,144 ----------- ----------- Preferred Stock - Nonredeemable............................. 116,200 116,200 ----------- ----------- Common Shareholders' Equity: Common shares, $5 par value - authorized 225,000,000 shares; 149,884,644 shares issued and 126,591,916 shares outstanding in 2003 and 149,375,847 shares issued and 127,562,031 shares outstanding in 2002...................................... 749,423 746,879 Capital surplus, paid in.................................. 1,105,386 1,108,338 Deferred contribution plan - employee stock ownership plan.......................................... (83,976) (87,746) Retained earnings......................................... 808,352 765,611 Accumulated other comprehensive income.................... 11,077 14,927 Treasury stock, 19,664,209 shares in 2003 and 18,022,415 shares in 2002........................... (360,698) (337,488) ----------- ----------- Common Shareholders' Equity................................. 2,229,564 2,210,521 ----------- ----------- Total Capitalization.......................................... 4,670,196 4,613,865 ----------- ----------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization......................... $10,273,203 $10,277,708 =========== =========== The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended March 31, ---------------------------------- 2003 2002 --------------- --------------- (Thousands of Dollars, except share information) Operating Revenues........................................ $ 1,688,437 $ 1,284,461 ------------ ------------ Operating Expenses: Operation - Fuel, purchased and net interchange power............ 1,069,295 726,615 Other................................................ 189,272 198,031 Maintenance............................................. 45,892 52,312 Depreciation............................................ 49,473 52,215 Amortization............................................ 57,299 20,244 Amortization of rate reduction bonds.................... 39,200 46,160 Taxes other than income taxes........................... 73,974 74,598 ------------ ------------ Total operating expenses............................ 1,524,405 1,170,175 ------------ ------------ Operating Income.......................................... 164,032 114,286 Interest Expense: Interest on long-term debt.............................. 32,940 32,972 Interest on rate reduction bonds........................ 27,861 29,562 Other interest.......................................... 2,744 4,353 ------------ ------------ Interest expense, net.............................. 63,545 66,887 ------------ ------------ Other Income/(Loss), Net.................................. 576 (13,997) ------------ ------------ Income Before Income Tax Expense.......................... 101,063 33,402 Income Tax Expense........................................ 39,469 13,370 ------------ ------------ Income Before Preferred Dividends of Subsidiaries......... 61,594 20,032 Preferred Dividends of Subsidiaries....................... 1,390 1,390 ------------ ------------ Net Income................................................ $ 60,204 $ 18,642 ============ ============ Basic and Fully Diluted Earnings Per Common Share......... $ 0.47 $ 0.14 ============ ============ Basic Common Shares Outstanding (average)................. 127,013,678 129,504,005 ============ ============ Fully Diluted Common Shares Outstanding (average)......... 127,111,272 129,754,946 ============ ============ The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, ------------------------------ 2003 2002 ------------- ------------- (Thousands of Dollars) Operating Activities: Income before preferred dividends of subsidiaries........... $ 61,594 $ 20,032 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation.............................................. 49,473 52,215 Deferred income taxes and investment tax credits, net..... (22,468) (22,803) Amortization.............................................. 96,499 66,404 Net amortization of recoverable energy costs.............. 6,269 22,053 Prepaid pension........................................... (7,650) (17,525) Net other sources of cash................................. 18,926 66,309 Changes in working capital: Receivables and unbilled revenues, net.................... 74,564 102,235 Fuel, materials and supplies.............................. 8,622 (368) Accounts payable.......................................... (88,484) (120,122) Accrued taxes............................................. (56,908) 32,232 Investments in securitizable assets....................... 23,149 (3,967) Other working capital (excludes cash)..................... (18,651) 24,288 ---------- ---------- Net cash flows provided by operating activities............... 144,935 220,983 ---------- ---------- Investing Activities: Investments in plant: Electric, gas and other utility plant..................... (92,705) (90,630) Competitive energy assets................................. (5,340) (6,571) Nuclear fuel.............................................. - (164) ---------- ---------- Cash flows used for investments in plant.................... (98,045) (97,365) Other investment activities, net............................ 6,571 (44,154) ---------- ---------- Net cash flows used in investing activities................... (91,474) (141,519) ---------- ---------- Financing Activities: Issuance of common shares................................... 6,979 1,130 Repurchase of common shares................................. (23,209) (18,250) Issuance of long-term debt.................................. 44,338 - Issuance of rate reduction bonds............................ - 50,000 Retirement of rate reduction bonds.......................... (42,901) (16,544) Net increase/(decrease) in short-term debt.................. 39,000 (60,500) Reacquisitions and retirements of long-term debt............ (14,324) (7,410) Cash dividends on preferred stock........................... (1,390) (1,390) Cash dividends on common shares............................. (17,469) (16,171) Other financing activities, net............................. (204) (177) ---------- ---------- Net cash flows used in financing activities................... (9,180) (69,312) ---------- ---------- Net increase in cash and cash equivalents..................... 44,281 10,152 Cash and cash equivalents - beginning of period............... 54,678 96,658 ---------- ---------- Cash and cash equivalents - end of period..................... $ 98,959 $ 106,810 ========== ========== 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 NU 2002 Form 10-K, and the current report on Form 8-K dated January 28, 2003. FINANCIAL CONDITION Overview -------- Consolidated: Northeast Utilities (NU or the company) earned $60.2 million, or $0.47 per share, in the first quarter of 2003, compared with earnings of $18.6 million, or $0.14 per share, in the first quarter of 2002. Results for the first quarter of 2002 included after-tax write-downs totaling $10 million, or $0.08 per share, related primarily to NU's investments in NEON Communications, Inc. (NEON) and Acumentrics Corporation (Acumentrics). First quarter 2003 results did not include any similar write-downs. Excluding those write-downs, NU earned $28.6 million in the first quarter of 2002. All per share amounts are reported on a fully diluted basis. Higher 2003 first quarter earnings for NU were a result of improved results at NU Enterprises. NU's earnings per share also benefited from its ongoing share repurchase program. NU repurchased approximately 1.6 million shares at an average price of $14.14 in the first quarter of 2003 and had approximately 126.6 million shares outstanding at March 31, 2003. NU can repurchase an additional 5.5 million shares through June 30, 2003, under a resolution adopted by the NU Board of Trustees. NU's revenues in the first quarter of 2003 increased to $1.7 billion from revenues of $1.3 billion in the same period of 2002 also contributing to the improvement in earnings. The increase in revenues is due to increases in electric and firm natural gas sales in 2003 as compared to 2002 as well as higher NU Enterprises' revenues. Utility Group: Overall, NU's Utility Group's performance in the first quarter of 2003 was comparable to the same period of 2002. The Connecticut Light and Power Company (CL&P) and Yankee Energy System, Inc. (Yankee) improved results from 2002 while Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO) earned less in the first quarter of 2003. Much colder weather in 2003 benefited the Utility Group and resulted in an 8.9 percent increase in regulated retail electric sales and an 18.3 percent increase in total regulated firm natural gas sales in the first three months of 2003, compared with the same period of 2002. The pre-tax earnings benefit related to these higher sales of approximately $21.5 million was offset by a reduction in pre-tax pension income and the absence of earnings related to the company's investment in the Seabrook nuclear power plant in the first quarter of 2003 compared with the same period of 2002. CL&P benefited from the colder weather resulting in a 9.1 percent increase in retail sales in the first quarter of 2003, compared with the same period of 2002. Also during the first quarter of 2003, CL&P recorded the final impacts of the Connecticut Department of Public Utility Control's (DPUC) final decision on the use of the proceeds from the Millstone sale which was issued on February 27, 2003. This decision resulted in an increase in CL&P's first quarter 2003 net income of $2.6 million. CL&P's earnings before the payment of preferred dividends totaled $26.7 million in the first quarter of 2003, compared with $21.7 million in the same period of 2002. Due to the colder weather which resulted in an 18.3 percent increase in firm natural gas sales in the first quarter of 2003 from the same period of 2002, Yankee earned $15.1 million in the first quarter of 2003, compared with $12.6 million in the same period of 2002. Other portions of the Utility Group recorded somewhat lower earnings, despite significant sales increases. PSNH earned $10.8 million in the first quarter of 2003, compared with $11.7 million in the same period of 2002, despite an 8.1 percent increase in retail sales. PSNH's 2003 earnings were negatively affected by a lower level of regulatory assets on which it earned a return, primarily due to the sale of the Seabrook nuclear units which was consummated on November 1, 2002. Net regulatory assets were reduced in November 2002 as a result of the sale of North Atlantic Energy Corporation's (NAEC) 35.98 percent ownership interest in Seabrook. The reduction in net regulatory assets will continue to negatively affect PSNH's 2003 to 2002 earnings comparisons. WMECO earned $6.1 million in the first quarter of 2003, compared with $6.9 million in the same period of 2002, despite a 9.2 percent increase in retail sales. The lower earnings in 2003 were due to lower pension income, which more than offset the impact of increased sales. NU Enterprises: NU Enterprises, which includes Select Energy, Inc. (Select Energy), NU's competitive wholesale and retail energy marketing subsidiary, earned $5.2 million in the first quarter of 2003, compared with a loss of $20.1 million in the first quarter of 2002. Select Energy's wholesale business includes 1,438 megawatts (MW) of generation and an energy trading function. The trading function has been significantly reduced in size over the past year. The wholesale business earned $6.8 million in the first quarter of 2003, compared with a loss of approximately $5.9 million in the same period of 2002. The first quarter 2002 results included approximately $10 million of after-tax energy trading losses. The 2003 results improved due to better management of the wholesale marketing portfolio, including better and more complete sourcing and the absence of net trading losses in the first quarter of 2003. Other areas of NU Enterprises, which include selling of electricity and natural gas to retail end-users and energy services businesses, lost approximately $1.6 million in the first quarter of 2003, compared with losses of $14.2 million in the first quarter of 2002. The 2003 improved retail results are primarily due to improved management of gas retail contracts along with improved margins on retail electric sales. Future Outlook -------------- Consolidated: NU continues to project earnings of between $1.10 per share and $1.30 per share in 2003. Despite a strong first quarter of 2003, management believes that a combination of more seasonable weather, lower pension income, and the absence of Seabrook-related earnings will result in lower quarterly results in the second, third and fourth quarters of 2003 than those reported by NU in the first quarter of 2003. Utility Group: The earnings range of between $1.10 per share and $1.30 per share includes earnings of between $1.05 per share and $1.15 per share at the Utility Group. NU Enterprises: NU continues to project earnings of between $0.15 per share and $0.25 per share at NU Enterprises. NU also continues to project parent company debt and other expenses of approximately $0.10 per share. Liquidity --------- Consolidated: NU's liquidity continues to be strong. At March 31, 2003, NU had $99 million of cash and cash equivalents on hand, a $44.3 million increase over March 31, 2002. At March 31, 2003, NU parent had $209.9 million invested in the NU system Money Pool, all of which was loaned to both the Utility Group and NU Enterprises. NU's net cash flows from operating activities decreased to $144.9 million in the first quarter of 2003 from $221 million in the first quarter of 2002. The primary reason for the decrease is the payment of $125.2 million of taxes primarily on the gain on the sale of Seabrook, offset by a $41.6 million increase in income before preferred dividends of subsidiaries. NU's capital expenditures totaled $98 million in the first quarter of 2003 compared to $97.4 million in the first quarter of 2002. NU also paid $14.3 million of debt maturities and $42.9 million of rate reduction bond maturities. In the first quarter of 2003, NU's long-term debt was impacted by two events. Select Energy Services, Inc. (SESI) issued $44.3 million of long-term debt that was used to refinance $6.5 million of short-term debt, with the remainder being used to finance ongoing projects. Also, NU executed an interest rate swap related to its $263 million fixed-rate senior notes, which resulted in a fair value adjustment to long-term debt of $5.1 million. The level of common dividends totaled $17.5 million in the first quarter of 2003, compared with $16.2 million in the first quarter of 2002. The increase resulted from NU paying a $0.1375 per share quarterly common dividend in the first quarter of 2003 and a $0.125 per share quarterly dividend in the first quarter of 2002. Management expects to continue to increase the dividend level periodically, subject to NU's ability to meet earnings targets and the judgment of its Board of Trustees at the time the dividends are declared. In 2001 and 2002, NU's Board of Trustees approved dividend increases at the time of the company's annual meeting, effective in the third quarter of those years. NU's next annual meeting will be held May 13, 2003, and management expects the Board of Trustees to consider a quarterly dividend increase at that time, effective in the third quarter of 2003. On April 8, 2003, the NU Board of Trustees approved a dividend of $0.1375 per share, payable June 30, 2003, to shareholders of record at June 1, 2003. Utility Group: At March 31, 2003, NU's Utility Group had $35 million borrowed on their $300 million revolving credit agreement. This credit line matures in November 2003. In addition to its revolving credit arrangement, CL&P can access up to $100 million by selling certain of its accounts receivable. At March 31, 2003, CL&P had $60 million of accounts receivable sold under this arrangement. At December 31, 2002, $40 million of accounts receivable were sold. These amounts are not reflected as obligations on the accompanying consolidated balance sheets. CL&P has withdrawn its application before the DPUC to fund approximately $200 million of spent nuclear fuel obligations. WMECO has an application pending with the Massachusetts Department of Telecommunications and Energy (DTE) to issue $100 million of unsecured long-term debt to fund its spent nuclear fuel obligations and to reduce short-term borrowings. NU Enterprises: NU parent and NU Enterprises had $60 million of borrowings and $28.2 million of letters of credit drawn on their $350 million revolving credit agreement. This credit line matures in November 2003. NU expects to issue $100 million to $150 million of unsecured, five-year fixed-rate senior notes in the second quarter of 2003 to refinance short-term debt. Implementation of Standard Market Design ---------------------------------------- On March 1, 2003, the New England Independent System Operator (ISO-NE) implemented a new standard market design (SMD). As part of SMD, locational marginal pricing (LMP) is utilized to assign value and causation to transmission congestion and line losses. Line losses represent losses of electricity as it is sent over transmission lines. The costs associated with transmission congestion and line losses are now assigned to the load zone in which they occur. Prior to March 1, 2003, those costs were spread across virtually all New England electric customers. As part of the implementation of SMD, ISO-NE established eight separate pricing zones in New England: three in Massachusetts and one in each of the other New England states. The three components of the LMP for each zone are an energy cost, congestion costs and line loss costs. LMP is expected to increase costs in zones that have inadequate or less cost-efficient generation and/or transmission constraints, such as Connecticut, and decrease costs in zones that have significant excess generation, such as Maine. The implementation of SMD may impact pricing under wholesale energy contracts depending on the energy delivery points chosen under those contracts. Utility Group: Connecticut has been designated a single load zone by ISO-NE. Due to high loads, transmission constraints and inadequate generation, Connecticut could experience significant additional congestion costs under SMD. ISO-NE estimates that the costs of transmission congestion for 2003 in New England under SMD will range between $50 million and $300 million. ISO- NE estimates that the majority of this congestion and its costs will be in Connecticut, where approximately 80 percent is expected to be paid by CL&P beginning on March 1, 2003. In addition to the congestion cost component of LMP, the determination of the energy delivery points associated with the standard offer service contracts will also produce significant line loss charges for CL&P. For March 2003, incremental LMP costs totaled $15.5 million. The majority of these incremental costs were associated with line losses, and management expects comparable monthly line loss charges for the remainder of 2003. CL&P's standard offer service contracts were executed in the fall of 1999. The delivery points in the contracts are at the suppliers' choice at any point on the New England power pool. Prior to March 1, 2003, delivery by the suppliers anywhere on the New England power pool resulted in the suppliers being charged and paying their respective share of socialized congestion costs. Subsequent to March 1, 2003, the delivery points chosen by the suppliers have been zones with no or negative congestion. Management believes that under the terms of its standard offer service contracts with its standard offer suppliers the incremental costs associated with losses and congestion between the delivery points chosen by the suppliers and CL&P's service territory in Connecticut are the responsibility of CL&P's customers. The $15.5 million of incremental costs incurred in March 2003 were recorded as recoverable energy costs at March 31, 2003, which are included in regulatory assets, for future recovery from customers. Management believes that these congestion and line loss charges are unavoidable, are part of the prudent cost of providing regulated electric service in Connecticut and that these costs should be paid for by customers. Accordingly, management believes that these costs should be recovered from its customers and will not impact 2003 earnings. On April 1, 2003, an informational hearing on SMD was held before the DPUC. On April 22, 2003, CL&P filed an application with the DPUC to recover their 2003 incremental LMP costs starting in May 2003. On May 1, 2003, the DPUC issued a final decision in response to CL&P's April 22, 2003 filing. In its decision, the DPUC directed CL&P to pursue legal remedies against its standard offer suppliers in an effort to assign liability for incremental LMP costs to the suppliers. The DPUC indicated that it will support CL&P's efforts and that CL&P's failure to aggressively pursue legal remedies may result in ultimate disallowance of recovery of LMP-related costs. Recovery of incremental LMP costs will be allowed through the Energy Adjustment Clause (EAC) but will be subject to refund and posting of a surety bond. Recovery is approved for sixty days, before the end of which period CL&P will be required to report the status of the steps it has taken in its legal actions against its standard offer suppliers. CL&P began recovery of the incremental March 2003 LMP costs of $15.5 million in its May 1, 2003 bills to customers. The incremental April 2003 LMP costs of $15.6 million will be collected in June 2003 bills. On May 5, 2003, CL&P filed a response to the decision with the DPUC. CL&P intends to request a declaratory judgment from the Federal Energy Regulatory Commission (FERC) to determine whether CL&P's standard offer service suppliers are responsible for incremental LMP costs. Additionally, CL&P intends to withhold payment of incremental LMP costs to its standard offer service suppliers pending resolution of this matter. Another factor affecting the level of CL&P costs is the designation of certain generating units by ISO-NE as units needed for system reliability. Some companies owning such units have applied to the FERC for "reliability must run" (RMR) treatment. RMR treatment allows these units to receive cost of service-based payments that recognize their reliability value. Prior to March 1, 2003, all RMR costs were spread across New England with all utilities being billed by ISO-NE based upon their share of New England's load, and NU's Utility Group was responsible for approximately 25 percent of these costs. Effective with the March 1, 2003 implementation of SMD, RMR costs will be allocated to the load zone in which the RMR unit is located. At present, the only load zone that will experience an RMR cost increase in which the Utility Group operates is Connecticut. Reliability costs have been previously approved for recovery by the DPUC in CL&P's 2001 Competitive Transition Assessment (CTA) reconciliation filing. All RMR costs, which began in 2002 and are considered reliability costs, have been recovered from customers to date and are subject to review in CL&P's 2002 CTA reconciliation filing, which was filed on March 31, 2003. PPL Corporation (PPL) and NRG Power Marketing, Inc. (NRG-PM) have sought RMR treatment from FERC for certain of their Connecticut units. PPL's request is still pending. NRG- PM's request for full cost of service recovery was denied; however, FERC did permit recovery of certain "going forward" maintenance costs, a temporary safe harbor from the ISO-NE price cap under certain circumstances, and the ability to set the energy price at certain times. Management cannot determine the impact on the components of LMP in the market related to these arrangements at this time. NU Enterprises: Select Energy currently serves 50 percent of CL&P's standard offer service. If it is ultimately concluded that the incremental LMP costs, which began on March 1, 2003, are the responsibility of the standard offer service suppliers, NU Enterprises' pre-tax earnings for the first quarter of 2003 would be reduced by $7.8 million. Also, NU Enterprises' and NU's earnings estimates do not include incremental LMP costs, which could be substantial for the remainder of 2003. Other impacts of SMD on its wholesale marketing business could be significant. As more information regarding the various impacts of SMD becomes available, there could be additional adverse effects that management cannot determine at this time. NU Enterprises -------------- Subsidiaries: NU Enterprises, Inc. is the parent company of Select Energy, Northeast Generation Company (NGC), SESI, Northeast Generation Services Company (NGS), and their respective subsidiaries, which is referred to as "NU Enterprises," collectively. Holyoke Water Power Company (HWP) is also included in NU Enterprises. Select Energy engages in wholesale and retail energy marketing activities and limited energy trading activities for price discovery and risk management of wholesale marketing activities. NU Enterprises owns 1,438 MW of generation capacity, consisting of 1,291 MW at NGC and 147 MW at HWP, which are used to support Select Energy's wholesale marketing business. 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, mechanical, and engineering contracting services. Outlook: NU Enterprises improved financial performance in the first quarter of 2003 compared to the first quarter of 2002. Management continues to believe that NU Enterprises will earn $0.15 to $0.25 per share for 2003. The wholesale marketing business obtained a significant level of new contracts in the first quarter of 2003. On March 1, 2003, Select Energy began serving Central Maine Power and Bangor-Hydro Electric Company under a new six-month agreement that is expected to generate $30 million in revenue. Select Energy was also successful in obtaining 1,200 MW of sales contracts in the latest New Jersey basic generation service auction. Select Energy estimates it will sell 700 MW for a 10-month period beginning August 1, 2003, and 500 MW for a 34-month period also beginning August 1, 2003. These contracts are expected to generate approximately $400 million in revenue. Select Energy also entered into a new six-month contract with National Grid for default service for certain of its subsidiaries that started in late April 2003. This contract is expected to generate $75 million of additional revenue through October 2003. In addition to new business, more normal precipitation would positively impact NGC's hydroelectric generating plants. Output has already increased in the first quarter of 2003 by about 40 percent compared to the first quarter of 2002 resulting in $1.6 million of additional earnings in 2003 as compared to 2002. Management currently believes that the wholesale marketing business will generate the gross margins required to meet their 2003 earnings estimate. Approximately 85 percent of the total margin needed to meet the wholesale marketing business' 2003 earnings estimate has been contracted in the first quarter of 2003. To meet the earnings estimate, the wholesale marketing business will need to successfully manage its portfolio of contracts to retain the estimated origination margins. The retail marketing business incurred losses of approximately $2 million in the first quarter of 2003, compared with losses of approximately $14 million in the first quarter of 2002. Management is hopeful that the retail group, as previously projected, will achieve break-even financial performance for 2003. However, through the first quarter of 2003, approximately 40 percent of the margin needed to cover projected costs and break-even has been contracted. Retail gas customers have been hesitant to commit to long-term contracts during this period of high prices. Select Energy is serving many of these customers on a month-to-month basis at relatively low margins. The retail marketing business will also need to manage its portfolio to realize the estimated margin for the contracts it has already entered into but has not yet served. Intercompany Transactions: CL&P's standard offer service purchases from Select Energy represented approximately $141 million of total NU Enterprises' revenues for the first quarter of 2003. Other transactions between CL&P and Select Energy amounted to approximately $36 million in revenues for Select Energy in the first quarter of 2003. Select Energy continues to provide standard offer service for its affiliate WMECO through December 31, 2003. WMECO's purchases from Select Energy represented approximately $39 million of total NU Enterprises' revenues in the first quarter of 2003. These amounts are eliminated in consolidation. NU Enterprises' Market and Other Risks -------------------------------------- Overview: For further information on risk management activities, see "Competitive Energy Subsidiaries' Market and Other Risks" in NU's combined report on Form 10-K. Risk management within NU Enterprises, including Select Energy, is organized by management to address the market, credit and operational exposures arising from the company's primary business segments: wholesale marketing (including limited trading) and retail marketing. The framework and degree to which these risks are managed and controlled is consistent with the limitations imposed by NU's Board of Trustees as established and communicated in NU's overall risk management policies and procedures. Wholesale and Retail Marketing: Select Energy manages its portfolio of wholesale and retail marketing contracts and assets to maximize value while maintaining an acceptable level of risk. At forward market prices in effect at March 31, 2003, the wholesale marketing portfolio, which includes the CL&P standard offer service contract and other contracts that extend to 2013, had a positive fair value. This positive fair value indicates a positive impact on Select Energy's gross margin in the future. However, there is significant volatility in the energy commodities markets that will impact this position between now and when the contracts are settled. Accordingly, there can be no assurances that Select Energy will realize the gross margin corresponding to the present positive fair value on its wholesale marketing portfolio. 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. Hedging: For information on derivatives used for hedging purposes and nontrading derivatives, see Note 2, "Derivative Instruments, Market Risk and Risk Management," to the consolidated financial statements. Energy Trading Activities in Wholesale Marketing: 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. Energy trading contracts are recorded at fair value, and changes in fair value impact earnings. At March 31, 2003, Select Energy had trading derivative assets of $162.8 million and trading derivative liabilities of $117 million on a counterparty- by-counterparty basis, for a net positive position of $45.8 million on the entire trading portfolio. These amounts are combined with other derivatives and are included in derivative assets and derivative liabilities on the accompanying consolidated balance sheets. Information regarding the other derivatives is included in Note 2, "Derivative Instruments, Market Risk and Risk Management," to the consolidated financial statements. There can be no assurances that Select Energy will actually realize cash corresponding to the present positive net fair value of its trading portfolio. Numerous factors could either positively or negatively affect the realization of the net fair value amount in cash. 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 determination of the portfolio's fair value is the responsibility of the middle office independent from the front office. The methods used to determine the fair value of energy trading contracts are identified and segregated in the table of fair value of contracts at March 31, 2003. 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. These transactions are modeled using available market information, generally accepted gas to electricity heat rate conversion models, or the Blacks option pricing model. Select Energy currently has one contract which is marked to model. This contract expires in 2006 and had a fair value of $4.7 million at March 31, 2003. Broker quotes for electricity are available through the year 2005, and models are generally used for the years 2006 and thereafter. Select Energy has sourced contracts with maturities in excess of four years. Accordingly, the value of these contracts and the related power supply contracts do not need to be determined with a model. Broker quotes for natural gas are available through 2013. 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 months ended March 31, 2003, 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. ------------------------------------------------------------------------------- Fair Value of Trading Contracts ------------------------------------------------------------------------------- (Millions of Dollars) At March 31, 2003 ------------------------------------------------------------------------------- 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 $(3.5) $ 0.1 $ - $(3.4) Prices provided by external sources 8.8 18.6 17.1 44.5 Prices based on models or other valuation methods - 4.7 - 4.7 ------------------------------------------------------------------------------- Totals $ 5.3 $23.4 $17.1 $45.8 ------------------------------------------------------------------------------- The fair value of energy trading contracts increased $4.8 million from $41 million at December 31, 2002 to $45.8 million at March 31, 2003. This increase is primarily due to a positive change in fair value of existing contracts and to contracts realized or otherwise settled during the period. There were no changes in valuation techniques or assumptions in the first quarter of 2003. ------------------------------------------------------------------------------- (Millions of Dollars) Total Fair Value ------------------------------------------------------------------------------- Three Months Ended March 31, 2003 ------------------------------------------------------------------------------- Fair value of trading contracts outstanding at the beginning of the period $41.0 Contracts realized or otherwise settled during the period (2.8) Fair value of new contracts when entered into during the period - Changes in fair values attributable to changes in valuation techniques and assumptions - Changes in fair value of contracts 7.6 ------------------------------------------------------------------------------- Fair value of trading contracts outstanding at the end of the period $45.8 ------------------------------------------------------------------------------- Changing Market: The breadth and depth of the market for energy trading and marketing products in Select Energy's market continues to be 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 are more often unable 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. 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 fair value of its long-term wholesale marketing energy contracts. Changes are occurring in the administration of transmission systems in territories in which Select Energy does business. Regional transmission organizations are being contemplated, and SMD was implemented in New England on March 1, 2003. As more information regarding these market changes becomes available, there could be additional adverse effects that management cannot determine at this time. 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. At March 31, 2003, approximately 75 percent of Select Energy's counterparty credit exposure to wholesale marketing and trading counterparties was cash collateralized or rated BBB- or better. Approximately five percent of the counterparty credit exposure was to unrated municipalities. At March 31, 2003, positions with three counterparties collectively represented approximately $66 million or 41 percent of the $162.8 million trading derivative assets. One of these counterparties has an investment grade credit rating. Another counterparty's position is secured with letters of credit and cash collateral. The third counterparty representing approximately $17.3 million is an unrated generation entity. None of the other counterparties represented more than 10 percent of the trading derivative assets. Select Energy manages the credit risk of its trading portfolio in accordance with established credit risk management policies and procedures. 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 levels to sub-investment grade, Select Energy could, under its present contracts, be asked to provide approximately $206 million of collateral or letters of credit to various unaffiliated counterparties and approximately $63 million to several independent system operators and unaffiliated local distribution companies, which management believes NU would be able to provide. 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. Business Development and Capital Expenditures --------------------------------------------- Utility Group: In October 2001, CL&P filed an application with the Connecticut Siting Council (CSC) to construct a new 345,000 volt overhead transmission line from Norwalk, Connecticut to Bethel, Connecticut. The line would help address the difficulties in serving the load in southwest Connecticut that create high LMP costs in Connecticut. In March 2003, CL&P revised its proposal following a settlement with the towns through which the transmission line is proposed. The proposal would place approximately half of the line underground and would increase the cost to $185 million from $135 million. The CSC is expected to vote on the proposal in June 2003, and CL&P hopes to begin construction by the end of 2003 and place the line into service in mid-2005. At March 31, 2003, CL&P had capitalized approximately $9.1 million related to this project. CL&P expects to file for approval of a separate 345,000 volt transmission line from Norwalk, Connecticut to Middletown, Connecticut in the third quarter of 2003. Estimated construction costs of this project are approximately $500 million. CL&P will jointly site this project with United Illuminating with CL&P owning 80 percent or approximately $400 million of the project. At March 31, 2003, CL&P had capitalized approximately $3.2 million related to this project. In September 2002, the CSC approved a plan to replace an undersea electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, at an estimated cost of $80 million. CL&P and the Long Island Power Authority each own approximately 50 percent of the line. The project still requires federal and New York state approvals. Given the approval process and the uncertainty created by the recent damage to the existing transmission line, the expected in-service date is currently under evaluation. At March 31, 2003, CL&P had capitalized approximately $5.3 million related to this project. Yankee Gas Services Company (Yankee Gas) is seeking to obtain rate approval from the DPUC to build a two billion cubic foot liquefied natural gas storage and production facility in Waterbury, Connecticut. Hearings were held in March 2003 with a final decision expected in the second quarter of 2003. If approved, construction of the facility, which is expected to cost approximately $60 million, could begin in the fourth quarter of 2003. At March 31, 2003, Yankee Gas had capitalized approximately $0.8 million related to this project. In late May 2003, the Governor of New Hampshire is expected to sign into law a bill that will permit PSNH to acquire the assets of Connecticut Valley Electric Company (CVEC). The acquisition of CVEC's assets will add 25 MW of new load to PSNH and approximately 10,000 customers in 13 towns. The CVEC transaction is still subject to approval by the FERC and the New Hampshire Public Utilities Commission (NHPUC) and is expected to close in December 2003. Merchant Energy Company Counterparty Exposures ---------------------------------------------- Certain subsidiaries of NU, including CL&P, Yankee Gas, Select Energy, and NGS 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 NRG is presently in default on debt service payments. Management does not expect that the resolution of the transactions with NRG will have a material adverse effect on NU's consolidated financial condition or results of operations. For further information, see Part II, Item 1, "Legal Proceedings," included in this combined report on Form 10-Q. Restructuring and Rate Matters ------------------------------ Connecticut - CL&P: Since retail competition began in Connecticut in 2000, only a small number of customers have opted to choose an alternate supplier as virtually all of CL&P's customers have continued to procure their electricity through CL&P's standard offer service. In 2003, Select Energy will continue to supply 50 percent of CL&P's standard offer supply service with NRG-PM, a subsidiary of NRG, contracted to supply 45 percent and a subsidiary of Duke Energy, Inc. contracted to supply the remaining 5 percent of service. CL&P continues to evaluate NRG-PM's ability to meet its obligations under the standard offer service contract, including the possibility that NRG-PM and the other standard offer service suppliers could ultimately be responsible for incremental LMP costs. 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, should they be incurred, would be permitted under the provisions of Connecticut's electric utility restructuring legislation and with the DPUC's prior decisions. On February 21, 2003, Fitch Ratings lowered its rating outlook on CL&P to negative as a result of its concern over timely recovery of purchased-power costs if NRG-PM were to default on its CL&P standard offer obligations and CL&P needs to acquire replacement supply service at significantly higher prices. On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds in the amount of approximately $1.2 billion from the sale of the Millstone units. The DPUC's final decision regarding this application was issued on February 27, 2003, and decreased the amount of net proceeds used to reduce stranded costs to $26.9 million from the $40.1 million reduction of stranded costs in its draft decision. The earnings impact in the first quarter of 2003 of the final decision resulted in an increase in net income of $2.6 million. CL&P continues to be subject to the earnings sharing mechanism implemented by the DPUC, under which CL&P's earnings in excess of a 10.3 percent return on equity will be shared equally by shareholders and ratepayers. The next earnings sharing calculation will be based on CL&P's earnings for the twelve months ended June 30, 2003. On April 3, 2003, CL&P filed its annual CTA and Systems Benefit Charge (SBC) reconciliation with the DPUC. For the year ended December 31, 2002, total CTA revenues and excess Generation Services Charge (GSC) revenues exceeded the CTA revenue requirement by approximately $93.5 million. CL&P has proposed that a portion of the CTA/GSC overrecovery be utilized to reduce nuclear stranded costs and the remaining amount be carried forward to 2003. For the same period, SBC revenues exceeded the SBC revenue requirement by approximately $21.4 million. After allocating a portion of the SBC overrecovery as ordered by the DPUC in a prior decision, CL&P has proposed that the remaining overrecovery of $18.6 million be applied to the CTA. Management expects a decision from the DPUC in this docket by the end of 2003. CL&P expects to file a distribution rate case with the DPUC in mid-2003 that would be effective January 1, 2004. Also in the second half of 2003, CL&P will need to secure bids for power supply contracts for 2004 to meet the needs of its customers. Management has not yet identified what level of rates it will request for 2004, but believes that several factors could combine to result in a significant increase in supply costs in 2004. The first is the expiration of current standard offer supply contracts. Another factor is the impact of LMP. CL&P's reliability improvements and transmission construction program will also impact the level of rates CL&P will request in 2004. The Connecticut state legislature is considering revisions to its 1998 electric utility industry restructuring statutes. Senate Bill 733 passed the Energy and Public Utilities and Environment committees in early 2003. Among other actions, the bill would 1) extend the offering of standard offer service rates for an additional three years to January 1, 2007; 2) allow base rates to return to 1996 levels, which are above existing levels; and 3) allow electric distribution companies, such as CL&P, to earn a transaction management fee for buying standard offer service for retail customers. The legislation, if passed and signed by the Connecticut Governor, would likely impact the aforementioned CL&P distribution rate case. Various Connecticut state budget proposals would direct approximately $100 million of electric utility revenues to the state's general fund, rather than toward energy conservation programs. In 2002, CL&P earned approximately $3.3 million in incentive payments on its energy conservation programs, and future earnings from conservation programs would be reduced if one of these budget proposals passes unchanged. Connecticut - Yankee Gas: In December 2002, the DPUC opened a new docket concerning Yankee Gas overearnings. Yankee Gas received a draft decision related to this docket on May 2, 2003. In the draft decision, the DPUC indicated that Yankee Gas' rates do not need to be adjusted. A final decision is expected on May 14, 2003. On May 7, 2003, the DPUC issued a draft decision in the Infrastructure Expansion Rate Mechanism (IERM) docket. The draft decision concludes that the basic concept of IERM is valid, appropriate and beneficial. In the draft decision, the DPUC estimated 2003 IERM overrecoveries of $3.6 million and proposed refund of overrecoveries to customers from December 2003 through February 2004. The final decision is scheduled for May 21, 2003. If the final decision is consisent with the draft decision, management does not expect that the decision will have a material impact on results of operations. New Hampshire: On February 1, 2003, in accordance with the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement) and state law, PSNH raised the transition service (TS) rate for residential and small commercial customers to $0.0460 per kilowatt-hour (kWh) from $0.0440 per kWh. On the same date, PSNH also raised its TS rate for large commercial and industrial customers to $0.0467 per kWh from $0.0440 per kWh. Given recent changes in the energy markets, PSNH is unable to determine if these rates will be adequate to currently recover its generation and purchased-power costs, including the recovery of carrying costs on PSNH's generation investment. If actual costs exceed those recoveries, PSNH will defer those costs for future recovery from customers through its Stranded Cost Recovery Charge (SCRC). If recoveries exceed PSNH's costs, those overrecoveries will be credited against PSNH's Part 3 stranded cost balance. PSNH's delivery rates are fixed by the Restructuring Settlement until February 1, 2004. Under the Restructuring Settlement, PSNH must file a rate case by December 31, 2003, for the purpose of commencing a review of PSNH's delivery rates. In April 2003, the New Hampshire state legislature approved legislation that would require PSNH to retain ownership of its fossil and hydroelectric generation assets until April 30, 2006. Subsequent to that time, PSNH may sell the assets if the NHPUC finds such sale to be in the best economic interest of customers. On April 23, 2003, the Governor of New Hampshire signed the bill into law. This legislation effectively extends the time period in which PSNH is required to supply TS and default service to its retail customers until the sale of its fossil and hydroelectric generation assets. The NHPUC will continue its regulatory oversight of TS and default service rates. On May 1, 2003, PSNH made a SCRC reconciliation filing with the NHPUC for the period January 1, 2002, through December 31, 2002. This filing reconciles stranded cost revenues against actual stranded costs with any difference being credited against Part 3 stranded costs or deferred for future recovery. Included in this stranded cost reconciliation filing are 1) a calculation of the generation costs for the filing period, 2) the Seabrook sale net proceeds calculation and 3) a request to recover, as a non-securitized stranded cost, certain deferred costs associated with PSNH's initial efforts to sell its fossil and hydroelectric generation assets as was previously required by the Restructuring Settlement. Management does not expect that the outcome of this docket will have a material adverse impact on PSNH's earnings or its financial position. Under New Hampshire law, PSNH is encouraged to enter into negotiations with independent power producers (IPPs) to terminate or renegotiate over-market power purchase obligations. In May 2003, the NHPUC is expected to issue an order approving a stipulation and settlement between PSNH, the NHPUC staff, the Office of Consumer Advocate, owners of fourteen small hydroelectric IPPs, and the Town of Goffstown, New Hampshire. Under the terms of this settlement, PSNH will make a lump sum payment totaling $20.4 million to the fourteen IPPs on May 31, 2003, in exchange for the termination of the existing power purchase obligations between PSNH and these IPPs. The buy out costs will be deferred as a regulatory asset, and recovered, including a return, over the remaining term of the initial contractual arrangements as a Part 2 stranded cost. Massachusetts: In December 2002, the DTE approved an overall increase of approximately 1.8 percent in WMECO's non-contract retail delivery rates, primarily reflecting slightly increased standard offer costs as well as other inflationary factors. WMECO's standard offer service is supplied by Select Energy at a rate for 2003 of approximately $0.0500 per kWh. An unaffiliated company won the bid to serve WMECO's default service for the period of January 1, 2003, through June 30, 2003, at an average price of $0.0510 per kWh. On March 31, 2003, WMECO filed its 2002 annual transition cost reconciliation with the DTE. This filing reconciled the recovery of stranded generation costs for calendar year 2002 and included the renegotiated purchased power contract related to the Vermont Yankee nuclear unit. Proceedings in this docket are expected to begin in the second half of 2003. On April 24, 2003, the DTE issued an order addressing three issues dealing with the future procurement of default service: 1) the cost components to be included in the calculation of default service rates, 2) default service pricing options and procurement strategies and 3) the appropriate role of distribution companies in moving their customers toward competitive supply. While making changes in the way WMECO procures default service supply for its customers, the order will not have an impact on WMECO's earnings. Critical Accounting Policies and Estimates ------------------------------------------ Funded Status of Pension Plan: At December 31, 2002, the assets of the NU noncontributory defined benefit plan (Plan) exceeded the accumulated benefit obligation (ABO) by approximately $78 million. The ABO is the obligation for employee service provided to date and does not assume future compensation increases. At April 30, 2003, the estimated fair value of Plan assets exceeded the December 31, 2002 ABO by approximately $101 million. If the ABO, when remeasured next on December 31, 2003, exceeds the fair value of Plan assets at that time, then NU would be required to record an additional minimum liability. Other Matters ------------- Other Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 4, "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 first quarter of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ---------------------- Amount Percent ------ ------- Operating Revenues $404 31% Operating Expenses: Fuel, purchased and net interchange power 343 47 Other operation (9) (4) Maintenance (6) (12) Depreciation (3) (5) Amortization 37 (a) Amortization of rate reduction bonds (7) (15) Taxes other than income taxes (1) (1) ---- ---- Total operating expenses 354 30 ---- ---- Operating income 50 44 ---- ---- Interest expense, net (3) (5) Other income/(loss), net 15 (a) ---- ---- Income before income tax expense 68 (a) Income tax expense 26 (a) ---- ---- Income before preferred dividends of subsidiaries 42 (a) ---- ---- Preferred dividends of subsidiaries - - ---- ---- Net income $ 42 (a)% ==== ==== (a) Percent greater than 100. Comparison of the First Quarter of 2003 to the First Quarter of 2002 Operating Revenues Total revenues increased by $404 million or 31 percent in the first quarter of 2003, compared with the same period in 2002, due to higher revenues from NU Enterprises ($231 million after intercompany eliminations) and higher Utility Group revenues ($173 million after intercompany eliminations). NU Enterprises' revenue increase is primarily due to higher wholesale revenues for Select Energy resulting from the New Jersey basic generation service. The Utility Group revenue increase is primarily due to higher retail revenue ($119 million) and higher wholesale revenue ($54 million). The regulated retail revenue increase is primarily due to higher retail electric sales ($73 million) and higher Yankee revenue resulting from higher purchased gas adjustment clause revenue ($27 million) and higher sales volumes ($21 million). Regulated retail electric kWh sales increased by 8.9 percent and firm natural gas sales increased by 18.3 percent in the first quarter of 2003. The regulated wholesale revenue increase is primarily due to higher prices in 2003. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased by $343 million or 47 percent in the first quarter of 2003, primarily due to higher wholesale activity at NU Enterprises ($257 million after intercompany eliminations) and higher purchased-power costs for the Utility Group primarily as a result of power purchased to serve higher retail sales ($90 million after intercompany eliminations). Other Operation and Maintenance Other operation and maintenance (O&M) expenses decreased $15 million in the first quarter of 2003, primarily due to lower nuclear expenses as a result of the sale of Seabrook in the last quarter of 2002 ($18 million), partially offset by higher distribution costs ($3 million). Depreciation Depreciation decreased in 2003 due to lower decommissioning expenses resulting from the sale of Seabrook in the last quarter of 2002 ($2 million), lower NU Enterprises' depreciation resulting from the study to lengthen the useful lives of certain generation assets ($3 million), partially offset by higher Utility Group depreciation resulting from higher plant balances. Amortization Amortization increased in 2003, primarily due to higher amortization related to the Utility Group's recovery of stranded costs in part resulting from higher wholesale revenue from the sale of IPP related energy ($37 million), partially offset by the decrease in amortization of rate reduction bonds ($7 million). Interest Expense, Net Interest expense, net decreased in the first quarter of 2003, primarily due to lower rate reduction bond interest ($2 million) and the retirement of NAEC's debt in November of 2002 ($1 million). Other Income/(Loss), Net Other income/(loss), net increased primarily due to a 2002 charge in the first quarter reflecting a write-down of NU's investments in NEON and Acumentrics ($15 million). Income Tax Expense Income tax expense increased due to higher taxable income. INDEPENDENT ACCOUNTANTS' REPORT To the Board of Trustees and Shareholders of Northeast Utilities We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries ("the Company") as of March 31, 2003, and the related condensed consolidated statements of income and cash flows for the three-month periods ended March 31, 2003 and 2002. 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. We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet and consolidated statement of capitalization of Northeast Utilities and subsidiaries as of December 31, 2002, and the related consolidated statements of income, comprehensive income, shareholders' equity, cash flows, and income taxes for the year then ended (not presented herein); and in our report dated January 28, 2003 (February 27, 2003 as to Note 8A), we expressed an unqualified opinion (which includes explanatory paragraphs with respect to the Company's adoption in 2001 of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended and its adoption in 2002 of Emerging Issues Task Force Issue 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" and SFAS No, 142 "Goodwill and Other Intangible Assets") on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2002 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Hartford, Connecticut May 9, 2003 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 this complete Form 10-Q 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 2002 Form 10-K, and the current report on Form 8-K dated January 28, 2003. The accompanying financial statements contain, in the opinion of management, all adjustments necessary to present fairly NU's and each NU company's financial position at March 31, 2003, the results of operations and statements of cash flows for the three-month periods ended March 31, 2003 and 2002. All adjustments are of a normal, recurring nature except those described in Note 4A. Due primarily to the seasonality of NU's business, the results of operations and statements of cash flows for the three-month periods ended March 31, 2003 and 2002, 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 of America 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 NU's Utility Group conforms to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically 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." The transmission and distribution businesses of CL&P, PSNH and WMECO, along with PSNH's generation business and Yankee Gas Services Company's (Yankee Gas) distribution business continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 to that portion of those businesses continues to be appropriate. Management also believes it is probable that NU's operating companies will recover their investments in long-lived assets, including regulatory assets. In addition, all material regulatory assets are earning an equity return, except for securitized regulatory assets which are not supported by equity. The components of NU's regulatory assets are as follows: --------------------------------------------------------------------- March 31, December 31, (Millions of Dollars) 2003 2002 --------------------------------------------------------------------- Recoverable nuclear costs $ 138.5 $ 85.4 Securitized regulatory assets 1,848.0 1,891.8 Income taxes, net 294.8 331.9 Unrecovered contractual obligations 237.1 239.3 Recoverable energy costs, net 293.3 299.6 Other 21.5 61.9 --------------------------------------------------------------------- Totals $2,833.2 $2,909.9 --------------------------------------------------------------------- C. New Accounting Standards Energy Trading and Risk Management Activities: In October 2002, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) reached consensuses on EITF Issue No. 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." One consensus rescinded EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities for Energy Trading Activities," under which Select Energy, Inc. (Select Energy) previously accounted for energy trading activities. This consensus requires companies engaged in energy trading activities to discontinue fair value accounting effective January 1, 2003, for contracts that do not meet the definition of a derivative in SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. NU adopted this consensus effective October 1, 2002. The second consensus requires that companies engaged in energy trading activities classify revenues and expenses associated with energy trading contracts on a net basis in revenues effective January 1, 2003. NU adopted net reporting effective July 1, 2002, before this consensus was reached by the EITF. The three months ended March 31, 2002, reflect net reporting. The effects of this reporting for the three months ended March 31, 2002, which have been previously reported, are as follows: --------------------------------------------------------------------- Operating Fuel, Purchased and Revenues Net Interchange Power --------------------------------------------------------------------- (Millions of Dollars) --------------------------------------------------------------------- Operating Revenues: As previously reported $1,910.7 $1,352.8 Impact of reclassification (626.2) (626.2) --------------------------------------------------------------------- As currently reported $1,284.5 $ 726.6 --------------------------------------------------------------------- The EITF continues to consider guidance on accounting for energy trading activities. The EITF has proposed Issue No. 02-L, "Reporting Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, and Not Held for Trading Purposes." EITF Issue No. 02-L is expected to address whether or not gains or losses on non-trading derivatives should be presented gross as revenues and expenses or on a net basis in revenues. Management will determine the impact, if any, that EITF Issue No. 02-L will have on the classification of revenues and expenses if and when the EITF reaches a consensus. Derivative Accounting: Effective January 1, 2001, NU adopted SFAS No. 133, as amended. In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amends SFAS No. 133. This new statement incorporates interpretations that were included in FASB Derivative Implementation Group guidance, clarifies certain conditions, and amends other existing pronouncements. Management is evaluating the impact of SFAS No. 149 on the consolidated financial statements, but does not believe that there will be a significant impact as a result of the issuance of this new statement. Asset Retirement Obligations: In June 2001, the 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 and when a reasonable estimate of the fair value of the liability can be made. NU adopted SFAS No. 143 on January 1, 2003. For the adoption of SFAS No. 143, management completed a review for potential asset retirement obligations (AROs), and did not identify any material AROs that have been incurred. However, management has identified certain removal obligations which arise in the ordinary course of business that either have a low probability of occurring or are not material in nature. These types of obligations would be recorded as they are incurred and relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain Federal Energy Regulatory Commission or state regulatory agency re-licensing issues. Guarantees: In November 2002, the FASB issued FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 requires that disclosures be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued and clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. FIN 45 does not apply to certain guarantee contracts, such as residual value guarantees provided by lessees in capital leases, guarantees that are accounted for as derivatives, guarantees that represent contingent consideration in a business combination, guarantees issued between either parents and their subsidiaries or corporations under common control, a parent's guarantee of a subsidiary's debt to a third party, and a subsidiary's guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent. The initial recognition and initial measurement provisions of FIN 45 are applicable to NU on a prospective basis to guarantees issued or modified after January 1, 2003. The adoption of the initial recognition and initial measurement provisions of FIN 45 had no impact on NU's consolidated financial statements. NU provides credit assurance in the form of guarantees and letters of credit in the normal course of business primarily for the financial performance obligations of NU Enterprises. NU would be required to perform under these guarantees in the event of non- performance under these obligations by NU Enterprises. NU currently has authorization from the Securities and Exchange Commission to provide up to $500 million of guarantees through September 30, 2003, and has applied for authority to increase this amount to $750 million. At March 31, 2003, payments guaranteed by NU, primarily on behalf of NU Enterprises, totaled $236.8 million. Additionally, NU had $28.2 million of letters of credit outstanding at March 31, 2003, and in conjunction with its investment in R.M. Services, Inc., NU guarantees a $3 million line of credit through 2005. Also, in conjunction with its wholly owned subsidiary Select Energy Services, Inc. (SESI), NU provides guarantees of approximately $2 million in connection with SESI's issuance of debt under arrangements with a third party financing of long-term receivables. D. Stock-Based Compensation NU maintains an Employee Stock Purchase Plan and other long-term, stock-based incentive plans under the Northeast Utilities Incentive Plan (Incentive Plan). NU accounts for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. No stock-based employee compensation cost for stock options is reflected in net income, as all options granted under those plans had an exercise price equal to or above the market value of the underlying common stock on the date of grant. At this time, NU has not elected to transition to expensing stock options under the fair value-based method of accounting for stock-based employee compensation. The following table illustrates the effect on net income and earnings per share (EPS) if NU had applied the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation related to stock options. --------------------------------------------------------------------- For the Three Months Ended --------------------------------------------------------------------- (Millions of Dollars, March 31, March 31, except per share amounts) 2003 2002 --------------------------------------------------------------------- Net income, as reported $60.2 $18.6 Total stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effects (0.6) (1.1) --------------------------------------------------------------------- Pro forma net income $59.6 $17.5 --------------------------------------------------------------------- Earnings per share: Basic and fully diluted - as reported $ 0.47 $ 0.14 Basic and fully diluted - pro forma $ 0.47 $ 0.14 --------------------------------------------------------------------- During the first quarter of 2003, NU granted approximately 375,000 shares of restricted stock under the Incentive Plan. For the three months ended March 31, 2003, approximately $0.1 million was expensed related to the restricted stock. No stock options were awarded. E. Other Income/(Loss), Net The pre-tax components of NU's other income/(loss), net items are as follows: --------------------------------------------------------------------- For the Three Months Ended --------------------------------------------------------------------- March 31, March 31, (Millions of Dollars) 2003 2002 --------------------------------------------------------------------- Investment write-downs $ - $(17.1) Investment income 3.9 5.0 Other, net (3.3) (1.9) --------------------------------------------------------------------- Totals $ 0.6 $(14.0) --------------------------------------------------------------------- F. Sale of Customer Receivables CL&P has an arrangement with a subsidiary of Citigroup, Inc. (Citigroup) under which CL&P can sell up to $100 million of accounts receivable. At March 31, 2003, CL&P had sold accounts receivable of $60 million to Citigroup with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. Additionally, at March 31, 2003, $6.1 million of assets were designated as collateral and restricted under the agreement with CRC. Concentrations of credit risk to the purchaser under this agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. At March 31, 2003, amounts sold to CRC from CL&P but not sold to the Citigroup subsidiary totaling $155.8 million are included in investments in securitizable assets on the consolidated balance sheets. At March 31, 2003 and December 31, 2002, $60 million and $40 million of accounts receivable were sold, respectively. 2. DERIVATIVE INSTRUMENTS, MARKET RISK AND RISK MANAGEMENT (NU, Select Energy, Yankee Gas) A. Derivative Instruments Effective January 1, 2001, NU adopted SFAS No. 133, as amended. Derivatives that are utilized for trading purposes are recorded at fair value with changes in fair value included in earnings. Other contracts that are derivatives but do not meet the definition of a cash flow hedge and cannot be designated as being used for normal purchases or normal sales are also recorded at fair value with changes in fair value included in earnings. 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 generally recognized in accumulated other comprehensive income until the underlying transactions occur. For those contracts that meet the definition of a derivative and meet the fair value hedge requirements, the changes in fair value of the effective portion of those contracts are generally recognized on the balance sheet as both the hedge and the hedged item are recorded at fair value. For contracts that meet the definition of a derivative but do not meet the hedging requirements, and for the ineffective portion of contracts that meet the cash flow hedge requirements, the changes in fair value of those contracts are recognized currently in earnings. Derivative contracts that are entered into as a normal purchase or sale and will result in physical delivery, and are documented as such, are recorded under accrual accounting. For information regarding recent accounting changes related to trading activities, see Note 1C, "New Accounting Standards," to the consolidated financial statements. During the first quarter of 2003, a negative $5.1 million, net of tax, was reclassified from other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized in earnings. A negative $0.2 million, net of tax, was recognized in earnings for those derivatives that were determined to be ineffective and for the ineffective portion of cash flow hedges. Also during the first quarter of 2003, new cash flow hedge transactions were entered into which hedge cash flows through 2005. As a result of these new transactions and market value changes since January 1, 2003, other comprehensive income decreased by $3.7 million, net of tax. Accumulated other comprehensive income at March 31, 2003, was a positive $11.8 million, net of tax (increase to equity), relating to hedged transactions, and it is estimated that $7.2 million of this balance, net of tax, will be reclassified as an increase to earnings within the next twelve months. Cash flows from the hedge contracts are reported in the same category as cash flows from the underlying hedged transaction. The tables below summarize the derivative assets and liabilities at March 31, 2003 and December 31, 2002. These amounts do not include premiums paid, which are recorded as prepayments and amounted to $20.2 million and $26.7 million at March 31, 2003 and December 31, 2002, respectively. These amounts also do not include premiums received, which are recorded as other current liabilities and amounted to $24.1 million and $33.9 million at March 31, 2003 and December 31, 2002, respectively. The premium amounts relate primarily to energy trading activities. --------------------------------------------------------------------- At March 31, 2003 --------------------------------------------------------------------- (Millions of Dollars) Assets Liabilities Total --------------------------------------------------------------------- Select Energy: Trading $162.8 $(117.0) $45.8 Nontrading 3.0 (0.8) 2.2 Hedging 24.7 (7.8) 16.9 --------------------------------------------------------------------- Yankee Gas: Hedging 2.8 - 2.8 --------------------------------------------------------------------- NU Parent: Hedging 5.1 - 5.1 --------------------------------------------------------------------- Total $198.4 $(125.6) $72.8 --------------------------------------------------------------------- --------------------------------------------------------------------- At December 31, 2002 --------------------------------------------------------------------- (Millions of Dollars) Assets Liabilities Total --------------------------------------------------------------------- Select Energy: Trading $102.9 $(61.9) $41.0 Nontrading 2.9 - 2.9 Hedging 22.8 (2.0) 20.8 --------------------------------------------------------------------- Yankee Gas: Hedging 2.3 - 2.3 --------------------------------------------------------------------- Total $130.9 $(63.9) $67.0 --------------------------------------------------------------------- Select Energy Trading: To gather market intelligence and utilize this information in risk management activities for the wholesale marketing business, Select Energy conducts energy trading activities in electricity, natural gas and oil, and therefore, experiences net open positions. Select Energy manages these open positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposure. Derivatives used in trading activities are recorded at fair value and included in the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recognized in operating revenues in the consolidated statements of income in the period of change. The net fair value positions of the trading portfolio at March 31, 2003 and at December 31, 2002 were assets of $45.8 million and $41.0 million, respectively. Select Energy's trading portfolio includes New York Mercantile Exchange (NYMEX) futures and options, the fair value of which is based on closing exchange prices; over-the-counter forwards and options, the fair value of which is based on the mid-point of bid and ask quotes; and bilateral contracts for the purchase or sale of electricity or natural gas, the fair value of which is modeled using available information from external sources based on recent transactions and validated with a gas forward curve and an estimated heat rate conversion. Select Energy's trading portfolio also includes transmission congestion contracts. The fair value of certain transmission congestion contracts is based on market inputs. Market information for other transmission congestion contracts is not available, and those contracts cannot be reliably valued. Management believes the amounts paid for these contracts are equal to their fair value. Select Energy Nontrading: Nontrading derivative contracts are used for delivery of energy related to Select Energy's retail and wholesale marketing activities. These contracts are not entered into for trading purposes, but are subject to fair value accounting because these contracts are derivatives that cannot be designated as normal purchases or sales, as defined by SFAS No. 133. These contracts cannot be designated as normal purchases or sales either because they are included in the New York energy market that settles financially or because the normal purchase and sale designation was not elected by management. The net fair values of nontrading derivatives at March 31, 2003 and at December 31, 2002 were assets of $2.2 million and $2.9 million, respectively. Select Energy Hedging: Select Energy utilizes derivative financial and commodity instruments, including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas purchased to meet firm sales 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 retail supply requirements. These derivatives have been designated as cash flow hedging instruments and are used to reduce the market risk associated with fluctuations in the price of electricity, natural gas, or oil. A derivative that hedges exposure to the variable cash flows of a forecasted transaction (a cash flow hedge) is initially recorded at fair value with changes in fair value recorded in other comprehensive income. Hedges impact earnings when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis. Select Energy 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 NYMEX futures contracts. Under these contracts, which also extend through 2004, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements. At March 31, 2003, the NYMEX futures contracts had notional values of $19.6 million and were recorded at fair value as a derivative asset of $5.4 million, net of tax, at March 31, 2003. In the first quarter of 2003 Select Energy designated new gas futures and financial gas swaps in New England to hedge cash flows throughout 2003 with a derivative liability value of $1.9 million, net of tax, at March 31, 2003. Yankee Gas Hedging: 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 unaffiliated customers is effectively fixed over the term of the gas service agreements with those customers for a period of time not extending beyond 2005. At March 31, 2003, the commodity swap agreement had a notional value of $9.1 million and was recorded at fair value as a derivative asset of $2.8 million with an offsetting fair value of the firm commitment recorded in current liabilities in the accompanying consolidated balance sheets. NU Parent Hedging: In March of 2003, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed-rate note that matures on April 1, 2012. As a perfectly matched fair value hedge the changes in fair value of the swap and the hedged debt instrument are recorded on the consolidated balance sheets but are equal and offset in the consolidated statements of income. The change in the fair value of the hedged debt of $5.1 million, including accrued interest, is included as long-term debt on the consolidated balance sheets. Additionally, the resulting changes in interest payments made are recorded as adjustments to interest expense. B. Market Risk Information Select Energy utilizes 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. 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, fair 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 fair value based on closing exchange prices. Select Energy Trading Portfolio: At March 31, 2003, Select Energy has calculated the market price resulting from a 10 percent change in forward market prices. That 10 percent change would result in approximately a positive or negative $0.8 million increase or decrease 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. Select Energy Retail and Wholesale Marketing Portfolio: 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 that 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 retail and wholesale marketing portfolio, which includes cash flow hedges and electricity, natural gas and oil contracts, assuming a 10 percent change in forward market prices. At March 31, 2003, a 10 percent change in market price would have resulted in an increase or decrease in fair value of approximately $10.8 million. The impact of a change in electricity, natural gas and oil prices on Select Energy's retail and wholesale marketing portfolio at March 31, 2003, is not necessarily representative of the results that will be realized when the commodities provided for in these contracts are physically delivered. C. Other Risk Management Activities Interest Rate Risk Management: NU manages its interest rate risk exposure by maintaining a mix of fixed and variable rate debt. At March 31, 2003, approximately 79 percent (67 percent including the debt subject to the fixed to floating interest rate swap in variable rate debt) of NU's long-term debt, including the current portion and fees and interest due for spent nuclear fuel disposal costs, is at a fixed interest rate. The remaining long-term debt is variable-rate and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in NU's variable interest rates, annual interest expense would have increased by $4.9 million. At March 31, 2003, NU parent maintained a fixed to floating interest rate swap to manage the risk associated with its $263 million of fixed-rate debt. Credit Risk Management: 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 margin 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. NU's Utility Group has a lower level of credit risk related to providing electric and gas distribution service than NU Enterprises. Credit risks and market risks at NU Enterprises 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 fair value 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. 3. GOODWILL AND OTHER INTANGIBLE ASSETS Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other Intangible Assets," which ceased amortization of goodwill and certain intangible assets with indefinite useful lives. SFAS No. 142 also required 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 is less than the carrying amount of the goodwill. There were no impairments or adjustments to the goodwill balances during the three-month periods ended March 31, 2003 and 2002. NU's reporting units that maintain goodwill are generally consistent with the operating segments underlying the reportable segments identified in Note 7, "Segment Information," to the consolidated financial statements. Consistent with the current way management reviews the operating results of its reporting units, NU's reporting units under the NU Enterprises reportable segment include: 1) the wholesale marketing reporting unit, 2) the retail marketing reporting unit, and 3) the services reporting unit. The wholesale marketing and retail marketing reporting units are comprised of the operations of Select Energy, Northeast Generation Company (NGC) and Holyoke Water Power Company (HWP), and the services reporting unit is comprised of the operations of SESI, Northeast Generation Services Company (NGS), Woods Network Services, Inc. (Woods Network), and the nonenergy related subsidiaries of Yankee Energy System, Inc. (Yankee). As a result, NU's revised reporting units that maintain goodwill are as follows: Yankee Gas, classified under the Utility Group - gas reportable segment, the wholesale and retail marketing reporting unit and the services reporting unit which are both classified under the NU Enterprises reportable segment. The goodwill balances of these reporting units are included in the table herein. At March 31, 2003, NU maintained $321 million of goodwill that is no longer being amortized, $17.2 million of identifiable intangible assets and $6.8 million of intangible assets not subject to amortization, totaling $345 million. At December 31, 2002, NU maintained $321 million of goodwill that is no longer being amortized, $18.1 million of identifiable intangible assets and $6.8 million of intangible assets not subject to amortization, totaling $345.9 million. These amounts are included on the consolidated balance sheets as goodwill and other purchased intangible assets, net. A summary of NU's goodwill balances at March 31, 2003 and December 31, 2002, by reportable segment and reporting unit is as follows: -------------------------------------------------------------------------- (Millions of Dollars) March 31, 2003 December 31, 2002 -------------------------------------------------------------------------- Utility Group - Gas: Yankee Gas $287.6 $287.6 NU Enterprises: Services 30.2 30.2 Wholesale and Retail Marketing 3.2 3.2 -------------------------------------------------------------------------- Totals $321.0 $321.0 -------------------------------------------------------------------------- At March 31, 2003 and December 31, 2002, NU's intangible assets and related accumulated amortization consisted of the following: -------------------------------------------------------------------------- At March 31, 2003 -------------------------------------------------------------------------- Gross Accumulated Net (Millions of Dollars) Balance Amortization Balance -------------------------------------------------------------------------- Intangible assets subject to amortization: Exclusivity agreement $17.7 $5.3 $12.4 Customer list 6.6 1.9 4.7 Customer backlog and employment related agreements 0.1 - 0.1 -------------------------------------------------------------------------- Totals $24.4 $7.2 $17.2 -------------------------------------------------------------------------- Intangible assets not subject to amortization: Customer relationships $ 3.8 Tradenames 3.0 -------------------------------------------- Totals $ 6.8 -------------------------------------------- -------------------------------------------------------------------------- At December 31, 2002 -------------------------------------------------------------------------- Gross Accumulated Net (Millions of Dollars) Balance Amortization Balance -------------------------------------------------------------------------- Intangible assets subject to amortization: Exclusivity agreement $17.7 $4.6 $13.1 Customer list 6.6 1.7 4.9 Customer backlog and employment related agreements 0.1 - 0.1 -------------------------------------------------------------------------- Totals $24.4 $6.3 $18.1 -------------------------------------------------------------------------- Intangible assets not subject to amortization: Customer relationships $ 3.8 Tradenames 3.0 -------------------------------------------- Totals $ 6.8 -------------------------------------------- NU recorded amortization expense of $0.9 million and $0.4 million for the three months ended March 31, 2003 and 2002, 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 2004 through 2008 is $3.6 million in 2004 through 2007 and no amortization expense in 2008. These amounts may vary as purchase price allocations are finalized or as acquisitions and dispositions occur in the future. 4. COMMITMENTS AND CONTINGENCIES A. Restructuring and Rate Matters (CL&P, PSNH, WMECO) Connecticut: Standard market design (SMD) was implemented in New England on March 1, 2003. As part of SMD, locational marginal pricing (LMP) is utilized to assign value and causation to transmission congestion and line losses. Management has recorded $15.5 million of incremental LMP costs incurred in March 2003 as recoverable energy costs, which are regulatory assets. Management believes that these incremental LMP costs are unavoidable, are part of the prudent cost of providing regulated electric service in Connecticut and that these costs are probable of recovery from its customers. The Department of Public Utility Control (DPUC) has directed CL&P to pursue legal remedies against its standard offer suppliers in an effort to assign liability for incremental LMP costs to the suppliers. The DPUC indicated that it will support CL&P's efforts and that CL&P's failure to aggressively pursue legal remedies may result in ultimate disallowance of recovery of LMP- related costs. Recovery of incremental LMP costs will be allowed through the Energy Adjustment Clause but will be subject to refund and posting of a surety bond. On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds in the amount of approximately $1.2 billion from the sale of the Millstone units. The DPUC's final decision regarding this application was issued on February 27, 2003, and decreased the amount of net proceeds used to reduce stranded costs to $26.9 million from the $40.1 million reduction of stranded costs included in the DPUC's draft decision. The earnings impact of the final decision resulted in an increase in first quarter 2003 net income of $2.6 million. New Hampshire: On May 1, 2003, PSNH made a Stranded Cost Recovery Charge reconciliation filing with the New Hampshire Public Utilities Commission for the period January 1, 2002, through December 31, 2002. This filing reconciles stranded cost revenues against actual stranded costs with any difference being credited against Part 3 stranded costs or deferred for future recovery. Included in this stranded cost reconciliation filing are 1) a calculation of the generation costs for the filing period, 2) the Seabrook sale net proceeds calculation and 3) a request to recover, as a non-securitized stranded cost, certain deferred costs associated with PSNH's initial efforts to sell its fossil and hydroelectric generation assets as was previously required by the "Agreement to Settle PSNH Restructuring." Management does not expect that the outcome of this docket will have a material adverse impact on PSNH's earnings or its financial position. Massachusetts: On March 31, 2003, WMECO filed its 2002 annual transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE). This filing reconciled the recovery of stranded generation costs for calendar year 2002 and included the renegotiated purchased power contract related to the Vermont Yankee nuclear unit. Proceedings in this docket are expected to begin in the second half of 2003. 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 $5.3 billion at March 31, 2003 as follows (millions of dollars): --------------------------------------------------------------------- Year --------------------------------------------------------------------- 2003 $3,121.0 2004 1,227.2 2005 505.5 2006 250.7 2007 210.1 --------------------------------------------------------------------- Total $5,314.5 --------------------------------------------------------------------- Select Energy's purchase contract amounts can exceed the amount expected to be reported in fuel, purchased and net interchange power because energy trading purchases are classified net in revenues. 5. COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO) Total comprehensive income, which includes all comprehensive income items, for NU is as follows: -------------------------------------------------------------------------- Three Months Ended March 31, -------------------------------------------------------------------------- (Millions of Dollars) 2003 2002 -------------------------------------------------------------------------- NU consolidated $56.4 $47.7 CL&P 25.8 20.4 PSNH 11.5 11.2 WMECO 6.2 6.9 -------------------------------------------------------------------------- Accumulated other comprehensive income fair value adjustments of NU's qualified cash flow hedging instruments are as follows: -------------------------------------------------------------------------- March 31, December 31, (Millions of Dollars, Net of Tax) 2003 2002 -------------------------------------------------------------------------- Balance at beginning of period $15.5 $(36.9) -------------------------------------------------------------------------- Hedged transactions recognized into earnings (5.1) 17.0 Change in fair value 4.3 29.2 Cash flow transactions entered into for the period (2.9) 6.2 -------------------------------------------------------------------------- Net change associated with the current period hedging transactions (3.7) 52.4 -------------------------------------------------------------------------- Total fair value adjustments included in accumulated other comprehensive income $11.8 $ 15.5 -------------------------------------------------------------------------- Accumulated other comprehensive income items unrelated to NU's qualified cash flow hedging instruments totaled $0.7 million in losses and $0.6 million in losses at March 31, 2003 and December 31, 2002, respectively. These amounts relate to unrealized losses on investments in marketable debt and equity instruments. 6. 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 certain securities are converted into common stock. The following table sets forth the components of basic and fully diluted EPS: -------------------------------------------------------------------------- (Millions of Dollars, Three Months Ended March 31, except share information) 2003 2002 -------------------------------------------------------------------------- Income before preferred dividends of subsidiaries $61.6 $20.0 Preferred dividends of subsidiaries 1.4 1.4 -------------------------------------------------------------------------- Net income $60.2 $18.6 -------------------------------------------------------------------------- Basic EPS common shares outstanding (average) 127,013,678 129,504,005 Dilutive effect of employee stock options 97,594 250,941 -------------------------------------------------------------------------- Fully diluted EPS common shares outstanding (average) 127,111,272 129,754,946 -------------------------------------------------------------------------- Basic and fully diluted EPS $0.47 $0.14 -------------------------------------------------------------------------- 7. SEGMENT INFORMATION (NU) NU is organized between the Utility Group and NU Enterprises based on the regulatory environment of each segment. The Utility Group segment, including both electric and gas utilities, represents approximately 72 percent and 81 percent of NU's total revenues for the three months ended March 31, 2003 and 2002, respectively, and primarily includes the operations of the electric utilities, CL&P, PSNH and WMECO, whose complete financial statements are included in NU's combined report on Form 10-Q. The Utility Group - gas segment includes the operations of Yankee Gas. Utility Group revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. On January 1, 2000, Select Energy began serving one half of CL&P's standard offer load for a four-year period ending December 31, 2003, at fixed prices. Total Select Energy revenues from CL&P for CL&P's standard offer load and for other transactions with CL&P, represented approximately $177 million or 26 percent in the first quarter of 2003 and approximately $158 million or 39 percent in the first quarter of 2002, of total NU Enterprises' revenues. Total CL&P purchases from NU Enterprises are eliminated in consolidation. Select Energy also provides basic generation service in the New Jersey market. Select Energy revenues related to these contracts represented $110.3 million or 16 percent of total NU Enterprises' revenues for the first quarter of 2003. Additionally, WMECO's purchases from Select Energy represented approximately $39 million and $1 million of total NU Enterprises' revenues in the first quarters of 2003 and 2002, respectively. No other individual customer represented in excess of 10 percent of NU Enterprises' revenues for the first quarter of 2003 or 2002. The NU Enterprises segment includes the operations of Select Energy, a corporation engaged in the trading, marketing, transportation, storage, and sale of energy commodities, in both wholesale and retail markets, in designated geographical areas; NGC, a corporation that acquires and manages generation facilities; SESI, a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional electric companies and electric utility companies; NGS, a corporation that maintains and services fossil or hydroelectric facilities and provides third-party electrical, mechanical, and engineering contracting services; HWP, a company engaged in the production of electric power and Woods Network. Eliminations and other in the following table includes the results for Mode 1 Communications, Inc., an investor in a fiber-optic communications network, the results of the nonenergy-related subsidiaries of Yankee and the company's investment in Acumentrics Corporation. Interest expense included in eliminations and other primarily relates to the debt of NU parent. Inter-segment eliminations of revenues and expenses are also included in eliminations and other. ------------------------------------------------------------------------------- For the Three Months Ended March 31, 2003 ------------------------------------------------------------------------------- Utility Group Eliminations (Millions of --------------- NU and Dollars) Electric Gas Enterprises Other Total ------------------------------------------------------------------------------- Operating revenues $1,065.4 $152.2 $ 689.8 $(219.0) $ 1,688.4 Depreciation and amortization (134.9) (5.7) (4.8) (0.6) (146.0) Other operating expenses (815.3) (116.2) (664.9) 218.0 (1,378.4) ------------------------------------------------------------------------------- Operating income/(loss) 115.2 30.3 20.1 (1.6) 164.0 Interest expense, net (43.6) (3.2) (11.2) (5.5) (63.5) Other (loss)/ income, net (0.3) (0.5) 0.6 0.8 0.6 Income tax (expense)/ benefit (27.4) (10.9) (4.3) 3.1 (39.5) Preferred dividends (1.4) - - - (1.4) ------------------------------------------------------------------------------- Net income/ (loss) $ 42.5 $ 15.7 $ 5.2 $ (3.2) $ 60.2 ------------------------------------------------------------------------------- Total assets $7,369.9 $965.7 $2,056.0 $(118.4) $10,273.2 ------------------------------------------------------------------------------- Total investments in plant $ 83.0 $ 9.1 $ 5.3 $ 0.6 $ 98.0 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- For the Three Months Ended March 31, 2002 ------------------------------------------------------------------------------- Utility Group Eliminations (Millions of --------------- NU and Dollars) Electric Gas Enterprises Other Total ------------------------------------------------------------------------------- Operating revenues $ 940.6 $104.3 $ 401.9 $(162.3) $ 1,284.5 Depreciation and amortization (104.7) (6.6) (6.8) (0.5) (118.6) Other operating expenses (722.4) (72.6) (415.2) 158.6 (1,051.6) ------------------------------------------------------------------------------- Operating income/(loss) 113.5 25.1 (20.1) (4.2) 114.3 Interest expense, net (47.8) (3.8) (11.1) (4.2) (66.9) Other income/ (loss), net 3.0 (0.5) (0.9) (15.6) (14.0) Income tax (expense)/ benefit (27.7) (8.3) 12.0 10.6 (13.4) Preferred dividends (1.4) - - - (1.4) ------------------------------------------------------------------------------- Net income/ (loss) $ 39.6 $ 12.5 $ (20.1) $ (13.4) $ 18.6 ------------------------------------------------------------------------------- Total investments in plant $ 78.7 $ 8.4 $ 6.6 $ 3.7 $ 97.4 ------------------------------------------------------------------------------- THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2003 2002 ---------- ------------ (Thousands of Dollars) ASSETS ------ Current Assets: Cash.................................................... $ 7,214 $ 159 Investments in securitizable assets..................... 155,759 178,908 Receivables, net........................................ 83,728 88,001 Accounts receivable from affiliated companies........... 72,276 51,060 Unbilled revenues....................................... 4,267 5,801 Notes receivable from affiliated companies.............. 30,200 1,900 Fuel, materials and supplies, at average cost........... 32,519 32,379 Prepayments and other................................... 24,681 19,407 ---------- ---------- 410,644 377,615 ---------- ---------- Property, Plant and Equipment: Electric utility........................................ 3,191,844 3,139,128 Less: Accumulated depreciation....................... 1,130,343 1,113,991 ---------- ---------- 2,061,501 2,025,137 Construction work in progress........................... 151,526 153,556 ---------- ---------- 2,213,027 2,178,693 ---------- ---------- Deferred Debits and Other Assets: Regulatory assets....................................... 1,674,132 1,702,677 Prepaid pension......................................... 283,023 276,173 Other .................................................. 90,896 96,925 ---------- ---------- 2,048,051 2,075,775 ---------- ---------- Total Assets.............................................. $4,671,722 $4,632,083 ========== ========== The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2003 2002 ---------- ------------ (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Accounts payable....................................... $ 152,571 $ 174,890 Accounts payable to affiliated companies............... 142,493 117,904 Accrued taxes.......................................... 55,619 34,350 Accrued interest....................................... 10,008 10,077 Other.................................................. 40,578 48,495 ---------- ---------- 401,269 385,716 ---------- ---------- Rate Reduction Bonds..................................... 1,213,541 1,245,728 ---------- ---------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes...................... 741,845 756,461 Accumulated deferred investment tax credits............ 92,777 93,408 Deferred contractual obligations....................... 229,456 234,537 Other.................................................. 336,760 276,325 ---------- ---------- 1,400,838 1,360,731 ---------- ---------- Capitalization: Long-Term Debt......................................... 828,518 827,866 ---------- ---------- Preferred Stock - Nonredeemable........................ 116,200 116,200 ---------- ---------- Common Stockholder's Equity: Common stock, $10 par value - authorized 24,500,000 shares; 6,035,205 shares outstanding in 2003 and 2002.................................... 60,352 60,352 Capital surplus, paid in............................. 327,062 327,299 Retained earnings.................................... 323,868 308,554 Accumulated other comprehensive income/(loss)........ 74 (363) ---------- ---------- Common Stockholder's Equity............................ 711,356 695,842 ---------- ---------- Total Capitalization..................................... 1,656,074 1,639,908 ---------- ---------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization..................... $4,671,722 $4,632,083 ========== ========== 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 March 31, ---------------------------- 2003 2002 -------------- ------------- (Thousands of Dollars) Operating Revenues........................................... $705,916 $604,420 -------- -------- Operating Expenses: Operation - Fuel, purchased and net interchange power............... 420,205 358,700 Other................................................... 75,839 70,212 Maintenance................................................ 11,178 14,524 Depreciation............................................... 25,416 23,296 Amortization of regulatory assets, net..................... 27,343 (3,031) Amortization of rate reduction bonds....................... 27,486 28,070 Taxes other than income taxes.............................. 49,362 48,538 -------- -------- Total operating expenses................................. 636,829 540,309 -------- -------- Operating Income............................................. 69,087 64,111 Interest Expense: Interest on long-term debt................................. 10,112 10,751 Interest on rate reduction bonds........................... 18,144 19,411 Other interest............................................. 403 247 -------- -------- Interest expense, net.................................... 28,659 30,409 -------- -------- Other Income, Net............................................ 744 3,479 -------- -------- Income Before Income Tax Expense............................. 41,172 37,181 Income Tax Expense........................................... 14,450 15,497 -------- -------- Net Income................................................... $ 26,722 $ 21,684 ======== ======== 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)
Three Months Ended March 31, ------------------------------ 2003 2002 ------------- ------------- (Thousands of Dollars) Operating Activities: Net income................................................................ $ 26,722 $ 21,684 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation............................................................ 25,416 23,296 Deferred income taxes and investment tax credits, net................... (21,708) (11,196) Net (deferral)/amortization of recoverable energy costs................. (6,116) 7,558 Amortization of regulatory assets, net.................................. 54,829 25,039 Prepaid pension......................................................... (6,850) (13,225) Net other sources of cash............................................... 46,386 29,013 Changes in working capital: Receivables and unbilled revenues, net.................................. (15,409) 3,347 Fuel, materials and supplies............................................ (140) (1,278) Accounts payable........................................................ 2,270 (16,731) Accrued taxes........................................................... 21,269 1,896 Investments in securitizable assets..................................... 23,149 (3,967) Other working capital (excludes cash)................................... (12,844) 16,501 ---------- ---------- Net cash flows provided by operating activities............................. 136,974 81,937 ---------- ---------- Investing Activities: Investments in plant...................................................... (56,976) (45,935) NU system Money Pool (lending)/borrowing.................................. (28,300) 35,850 Other investment activities, net.......................................... (900) (53,842) ---------- ---------- Net cash flows used in investing activities................................. (86,176) (63,927) ---------- ---------- Financing Activities: Retirement of rate reduction bonds........................................ (32,187) - Cash dividends on preferred stock......................................... (1,390) (1,390) Cash dividends on common stock............................................ (10,018) (15,017) Other financing activities, net........................................... (148) (130) ---------- ---------- Net cash flows used in financing activities................................. (43,743) (16,537) ---------- ---------- Net increase in cash........................................................ 7,055 1,473 Cash - beginning of period.................................................. 159 773 ---------- ---------- Cash - end of period........................................................ $ 7,214 $ 2,246 ========== ========== 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 and the NU 2002 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the first quarter of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ---------------------- Amount Percent ------ ------- Operating Revenues $101 17% Operating Expenses: Fuel, purchased and net interchange power 61 17 Other operation 5 8 Maintenance (3) (23) Depreciation 2 9 Amortization of regulatory assets, net 30 (a) Amortization of rate reduction bonds - - Taxes other than income taxes 1 2 ---- ---- Total operating expenses 96 18 ---- ---- Operating income 5 8 ---- ---- Interest expense, net (2) (6) Other income, net (3) (79) ---- ---- Income before income tax expense 4 11 Income tax expense (1) (7) ---- ---- Net income $ 5 23% ==== ==== (a) Percent greater than 100. Operating Revenues Operating revenues increased by $101 million or 17 percent in the first quarter of 2003, primarily due to higher wholesale revenues ($54 million) and higher retail revenues ($47 million). Wholesale revenues were higher primarily due to higher market prices in 2003. Retail revenues increased primarily due to higher retail sales. Retail kilowatt-hour sales increased by 9.1 percent in 2003, of which 5.3 percent was related to weather. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased in the first quarter of 2003, primarily due to higher standard offer purchases and purchased-power costs required to meet the load requirements from the increased retail sales. Other Operation and Maintenance Other O&M expenses increased by $2 million in the first quarter of 2003, primarily due to higher administrative and general expenses resulting from a lower pension income offset to expense ($5 million) and higher transmission and distribution expenses ($5 million), partially offset by lower related nuclear expenses ($8 million) as a result of the final DPUC order regarding the CL&P Millstone use of proceeds docket. Depreciation Depreciation expense increased in the first quarter of 2003, primarily due to higher utility plant balances in 2003 resulting from plant additions. Amortization Amortization increased in the first quarter of 2003, primarily due to higher amortization related to the recovery of stranded costs ($43 million), partially offset by lower amortization of the nuclear investment ($14 million). Taxes Other Than Income Taxes Taxes other than income taxes increased in the first quarter of 2003, primarily due to higher gross earnings tax due to higher sales. Interest Expense, Net Interest expense, net decreased in the first quarter of 2003, primarily due to lower interest on rate reduction bonds. Other Income, Net Other income, net decreased in the first quarter of 2003, primarily due to lower miscellaneous non-operating income ($1 million), lower interest and dividend income ($1 million), and higher charitable donations made in 2003 ($1 million). Income Tax Expense Income tax expense decreased in the first quarter of 2003, primarily due to a reduction in flow through depreciation, and an increase in state tax credits. LIQUIDITY In addition to its revolving credit arrangement, CL&P can access up to $100 million by selling certain of its accounts receivable. At March 31, 2003, CL&P had $60 million of accounts receivable sold under this arrangement. At December 31, 2002, $40 million of accounts receivable were sold. These amounts are not reflected as obligations on the accompanying consolidated balance sheets. CL&P has withdrawn its application before the DPUC to fund approximately $200 million of spent nuclear fuel obligations. CL&P's net cash flows provided by operating activities increased to $137 million in the first quarter of 2003, compared with $81.9 million during the first quarter of 2002. Cash flows provided by operating activities increased primarily due to the increase in the amortization of regulatory assets related to the recovery of stranded costs and changes in working capital items. Financing activities decreased with the level of common dividends totaling $10 million in the first quarter of 2003 compared to $15 million in the first quarter of 2002. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2003 2002 ---------- ------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash...................................................... $ 4,425 $ 5,319 Receivables, net.......................................... 70,167 68,204 Accounts receivable from affiliated companies............. 13,326 9,667 Unbilled revenues......................................... 29,821 32,004 Notes receivable from affiliated companies................ 3,300 23,000 Fuel, materials and supplies, at average cost............. 53,098 49,182 Prepayments and other..................................... 4,035 10,032 ---------- ---------- 178,172 197,408 ---------- ---------- Property, Plant and Equipment: Electric utility.......................................... 1,445,749 1,431,774 Other..................................................... 6,194 6,195 ---------- ---------- 1,451,943 1,437,969 Less: Accumulated depreciation......................... 722,747 715,800 ---------- ---------- 729,196 722,169 Construction work in progress............................. 55,074 50,547 ---------- ---------- 784,270 772,716 ---------- ---------- Deferred Debits and Other Assets: Regulatory assets......................................... 832,361 859,871 Other .................................................... 83,218 92,280 ---------- ---------- 915,579 952,151 ---------- ---------- Total Assets................................................ $1,878,021 $1,922,275 ========== ========== The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2003 2002 ---------- ------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to banks................................... $ 15,000 $ - Obligations under capital leases - current portion....... 215 206 Accounts payable......................................... 47,208 54,588 Accounts payable to affiliated companies................. 8,235 4,008 Accrued taxes............................................ 15,145 65,317 Accrued interest......................................... 14,571 11,333 Unremitted rate reduction bond collections............... 20,742 25,555 Other.................................................... 14,809 12,468 ---------- ----------- 135,925 173,475 ---------- ----------- Rate Reduction Bonds....................................... 502,650 510,841 ---------- ----------- Obligations Under Capital Leases........................... 929 986 ---------- ----------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes........................ 351,413 359,910 Accumulated deferred investment tax credits.............. 2,534 2,680 Deferred contractual obligations......................... 54,958 56,165 Accrued pension.......................................... 39,708 37,933 Other.................................................... 49,458 51,170 ---------- ----------- 498,071 507,858 ---------- ----------- Capitalization: Long-Term Debt........................................... 407,285 407,285 ---------- ----------- Common Stockholder's Equity: Common stock, $1 par value - authorized 100,000,000 shares; 301 shares outstanding in 2003 and 2002...................................... - - Capital surplus, paid in............................... 126,811 126,937 Retained earnings...................................... 205,825 194,998 Accumulated other comprehensive income/(loss).......... 525 (105) ---------- ----------- Common Stockholder's Equity.............................. 333,161 321,830 ---------- ----------- Total Capitalization....................................... 740,446 729,115 ---------- ----------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization....................... $1,878,021 $ 1,922,275 ========== =========== 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 March 31, --------------------------- 2003 2002 --------------------------- (Thousands of Dollars) Operating Revenues.......................................... $256,895 $242,381 -------- -------- Operating Expenses: Operation - Fuel, purchased and net interchange power.............. 137,065 119,339 Other.................................................. 28,906 29,992 Maintenance............................................... 13,445 12,901 Depreciation.............................................. 10,607 10,069 Amortization of regulatory assets, net.................... 17,570 14,592 Amortization of rate reduction bonds...................... 9,246 15,495 Taxes other than income taxes............................. 8,673 9,243 -------- -------- Total operating expenses................................ 225,512 211,631 -------- -------- Operating Income............................................ 31,383 30,750 Interest Expense: Interest on long-term debt................................ 3,847 4,847 Interest on rate reduction bonds.......................... 7,410 7,702 Other interest............................................ 247 182 -------- -------- Interest expense, net................................... 11,504 12,731 -------- -------- Other (Loss)/Income, Net.................................... (1,211) 97 -------- -------- Income Before Income Tax Expense............................ 18,668 18,116 Income Tax Expense.......................................... 7,841 6,387 -------- -------- Net Income.................................................. $ 10,827 $ 11,729 ======== ======== 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)
Three Months Ended March 31, ------------------------------ 2003 2002 ------------- ------------- (Thousands of Dollars) Operating activities: Net Income.......................................................... $ 10,827 $ 11,729 Adjustments to reconcile to net cash flows (used in)/provided by operating activities: Depreciation...................................................... 10,607 10,069 Deferred income taxes and investment tax credits, net............. (8,256) (11,119) Net amortization of recoverable energy costs...................... 5,847 5,548 Amortization of regulatory assets, net............................ 26,816 30,087 Net other uses of cash............................................ (1,783) (14,700) Changes in working capital: Receivables and unbilled revenues, net............................ (3,439) (2,121) Fuel, materials and supplies...................................... (3,916) 1,411 Accounts payable.................................................. (3,152) 20,719 Accrued taxes..................................................... (50,172) 18,616 Other working capital (excludes cash)............................. 7,394 14,828 -------- -------- Net cash flows (used in)/provided by operating activities............. (9,227) 85,067 -------- -------- Investing Activities: Investments in plant................................................ (21,621) (27,150) NU system Money Pool borrowing/(lending)............................ 19,700 (30,400) Other investment activities, net.................................... 3,493 (4,002) -------- -------- Net cash flows provided by/(used in) investing activities............. 1,572 (61,552) -------- -------- Financing Activities: Issuance of rate reduction bonds.................................... - 50,000 Retirement of rate reduction bonds.................................. (8,191) (13,795) Net increase/(decrease) in short-term debt.......................... 15,000 (45,500) Cash dividends on common stock...................................... - (16,750) Other financing activities, net..................................... (48) 3,354 -------- -------- Net cash flows provided by/(used in) financing activities............. 6,761 (22,691) -------- -------- Net (decrease)/increase in cash....................................... (894) 824 Cash - beginning of period............................................ 5,319 1,479 -------- -------- Cash - end of period.................................................. $ 4,425 $ 2,303 ======== ======== 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 and the NU 2002 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the first quarter of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ---------------------- Amount Percent ------ ------- Operating Revenues $ 15 6% Operating Expenses: Fuel, purchased and net interchange power 18 15 Other operation (1) (4) Maintenance 1 4 Depreciation - - Amortization of regulatory assets, net 3 20 Amortization of rate reduction bonds (6) (40) Taxes other than income taxes (1) (6) ---- ---- Total operating expenses 14 7 ---- ---- Operating income 1 2 ---- ---- Interest expense, net (1) (10) Other income, net (1) (a) ---- ---- Income before income tax expense 1 3 Income tax expense 2 23 ---- ---- Net income $ (1) (8)% ==== ==== (a) Percent greater than 100. Operating Revenues Total revenues increased by $15 million or 6 percent in the first quarter of 2003, as compared to the same period of 2002, primarily due to higher retail revenue ($19 million), partially offset by lower wholesale revenue ($5 million). Retail revenue increased primarily due to higher retail sales. Retail kilowatt-hour sales increased by 8.1 percent in 2003, of which 4.7 percent was related to the weather. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power increased primarily as result of the increase in retail sales due to the colder weather and increased fuel prices in 2003. Amortization Amortization decreased primarily due to the scheduled amortization of principle for the rate reduction bonds, partially offset by the increased recovery of stranded costs. Taxes Other Than Income Taxes Taxes other than income taxes decreased primarily due to lower property tax. Interest Expense, Net Interest expense, net decreased in 2003 primarily due to lower interest costs associated with the refinancing of the pollution control revenue bonds. Other Income, Net Other income, net is lower primarily due to lower income associated with the sale of property. Income Tax Expense Income tax expense increased primarily due to higher book taxable income. LIQUIDITY PSNH's net cash flows used in operating activities totaled $9.2 million in the first quarter of 2003, compared with net cash flows provided by operating activities of $85 million during the first quarter of 2002. Cash flows used in operating activities decreased primarily due to the changes in working capital items, primarily the payment of taxes on the gain on the sale of Seabrook. There was a lower level of investing activities in the first quarter of 2003, as compared with the first quarter of 2002, primarily due to borrowings from the NU system Money Pool and a reduction in investments in plant for the first quarter of 2003. There was also a lower level of financing activities in the first quarter of 2003 primarily due to an increase in short-term debt. At March 31, 2003, PSNH had $15 million borrowed under the Utility Group's $300 million revolving credit agreement. This credit line matures in November 2003. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2003 2002 ------------- ------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash........................................................ $ 1 $ 123 Receivables, net............................................ 41,998 42,203 Accounts receivable from affiliated companies............... 27 6,369 Unbilled revenues........................................... 11,233 8,944 Fuel, materials and supplies, at average cost............... 2,360 1,821 Prepayments and other....................................... 1,308 1,470 ----------- ----------- 56,927 60,930 ----------- ----------- Property, Plant and Equipment: Electric utility............................................ 593,193 590,153 Less: Accumulated depreciation........................... 197,980 195,804 ----------- ----------- 395,213 394,349 Construction work in progress............................... 11,816 11,860 ----------- ----------- 407,029 406,209 ----------- ----------- Deferred Debits and Other Assets: Regulatory assets........................................... 269,656 283,702 Prepaid pension............................................. 69,191 67,516 Other ...................................................... 19,578 18,304 ----------- ----------- 358,425 369,522 ----------- ----------- Total Assets.................................................. $ 822,381 $ 836,661 =========== =========== The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Unaudited)
March 31, December 31, 2003 2002 ----------- ------------ (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to banks................................... $ 10,000 $ 7,000 Notes payable to affiliated companies.................... 69,200 85,900 Accounts payable......................................... 16,050 17,730 Accounts payable to affiliated companies................. 11,275 6,233 Accrued taxes............................................ 7,110 4,334 Accrued interest......................................... 1,234 2,059 Other.................................................... 9,318 8,005 ---------- ---------- 124,187 131,261 ---------- ---------- Rate Reduction Bonds....................................... 140,220 142,742 ---------- ---------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes........................ 217,190 222,065 Accumulated deferred investment tax credits.............. 3,578 3,662 Deferred contractual obligations......................... 62,416 63,767 Other.................................................... 12,561 13,213 ---------- ---------- 295,745 302,707 ---------- ---------- Capitalization: Long-Term Debt........................................... 102,143 101,991 ---------- ---------- Common Stockholder's Equity: Common stock, $25 par value - authorized 1,072,471 shares; 434,653 shares outstanding in 2003 and 2002...................................... 10,866 10,866 Capital surplus, paid in............................... 69,656 69,712 Retained earnings...................................... 79,541 77,476 Accumulated other comprehensive income/(loss).......... 23 (94) ---------- ---------- Common Stockholder's Equity.............................. 160,086 157,960 ---------- ---------- Total Capitalization....................................... 262,229 259,951 ---------- ---------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization....................... $ 822,381 $ 836,661 ========== ========== 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 March 31, ------------------------- 2003 2002 ------------------------- (Thousands of Dollars) Operating Revenues......................................... $104,786 $ 96,005 -------- -------- Operating Expenses: Operation - Fuel, purchased and net interchange power............. 53,003 50,200 Other................................................. 13,770 10,564 Maintenance.............................................. 3,134 2,918 Depreciation............................................. 3,471 3,189 Amortization of regulatory assets, net................... 11,273 7,904 Amortization of rate reduction bonds..................... 2,469 2,595 Taxes other than income taxes............................ 2,972 2,940 -------- -------- Total operating expenses........................... 90,092 80,310 -------- -------- Operating Income........................................... 14,694 15,695 Interest Expense: Interest on long-term debt............................... 792 765 Interest on rate reduction bonds......................... 2,308 2,449 Other interest........................................... 376 358 -------- -------- Interest expense, net................................. 3,476 3,572 -------- -------- Other Loss, Net............................................ (5) (556) -------- -------- Income Before Income Tax Expense........................... 11,213 11,567 Income Tax Expense......................................... 5,145 4,677 -------- -------- Net Income................................................. $ 6,068 $ 6,890 ======== ======== The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, ------------------------------- 2003 2002 ------------- ------------ (Thousands of Dollars) Operating Activities: Net income.......................................................... $ 6,068 $ 6,890 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation...................................................... 3,471 3,189 Deferred income taxes and investment tax credits, net............. (3,795) (3,153) Net amortization of recoverable energy costs...................... 149 722 Amortization of regulatory assets, net............................ 13,742 10,499 Prepaid pension................................................... (1,675) (3,025) Net other uses of cash............................................ (3,596) (1,953) Changes in working capital: Receivables and unbilled revenues, net............................ 4,258 6,505 Fuel, materials and supplies...................................... (538) (36) Accounts payable.................................................. 3,362 (22,644) Accrued taxes..................................................... 2,776 9,212 Other working capital (excludes cash)............................. 765 1,087 ---------- ---------- Net cash flows provided by operating activities....................... 24,987 7,293 ---------- ---------- Investing Activities: Investments in plant................................................ (4,395) (4,702) NU system Money Pool (lending)/borrowing............................ (16,700) 18,700 Other investment activities, net.................................... (482) 620 ---------- ---------- Net cash flows (used in)/provided by investing activities............. (21,577) 14,618 ---------- ---------- Financing Activities: Retirement of rate reduction bonds.................................. (2,522) (2,748) Net increase/(decrease) in short-term debt.......................... 3,000 (15,000) Cash dividends on common stock...................................... (4,003) (4,001) Other financing activities, net..................................... (7) (6) ---------- ---------- Net cash flows used in financing activities........................... (3,532) (21,755) ---------- ---------- Net (decrease)/increase in cash....................................... (122) 156 Cash - beginning of period............................................ 123 599 ---------- ---------- Cash - end of period.................................................. $ 1 $ 755 ========== ========== 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 and the NU 2002 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the first quarter of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ---------------------- Amount Percent ------ ------- Operating Revenues $ 9 9% Operating Expenses: Fuel, purchased and net interchange power 3 6 Other operation 3 30 Maintenance - - Depreciation - - Amortization of regulatory assets, net 4 43 Amortization of rate reduction bonds - - Taxes other than income taxes - - ---- ---- Total operating expenses 10 12 ---- ---- Operating income (1) (6) ---- ---- Interest expense, net - - Other income, net - - ---- ---- Income before income tax expense - - Income tax expense - - ---- ---- Net income $ (1) (12)% ==== ==== Operating Revenues Total revenues increased by $9 million or 9 percent in the first quarter of 2003, compared with the same period in 2002, due to higher wholesale revenues ($5 million), and higher retail revenues ($4 million). Wholesale revenues were higher primarily due to higher market prices in 2003. Retail revenues were higher primarily due to higher retail sales. Retail sales increased by 9.2 percent, of which 4.9 percent was related to the colder weather. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased by $3 million or 6 percent in the first quarter of 2003, primarily due to higher standard offer purchases as a result of the retail sales increases. Other Operation Other operation expenses increased $3 million in the first quarter of 2003, due to higher administration and general expenses primarily resulting from lower pension income ($2 million) and higher transmission expense ($1 million). Amortization Amortization increased in 2003, primarily due to higher amortization related to the recovery of stranded costs. LIQUIDITY WMECO's net cash flows provided by operating activities increased to $25 million in the first quarter of 2003, compared with $7.3 million during the first quarter of 2002. Cash flows provided by operating activities increased primarily due to changes in accounts payable, offset by changes in accrued taxes. Financing activities decreased with the level of common dividends totaling $4 million in the first quarters of 2003 and 2002. At March 31, 2003, WMECO had $10 million borrowed under the Utility Group's $300 million revolving credit agreement. This credit line matures in November 2003. WMECO has an application pending with the DTE to issue $100 million of unsecured long-term debt to fund its spent nuclear fuel obligations and to reduce short-term borrowings. 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," Note 2B, "Derivative Instruments, Market Risk and Risk Management - Market Risk Information," and Note 2C, "Derivative Instruments, Market Risk and Risk Management - Other Risk Management Activities," to the consolidated financial statements 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 by 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. NRG Energy, Inc. (NRG) - Credit Rating Status Recent changes in the credit status of NRG have impacted the contractual relationships between NRG and CL&P, Yankee Gas and Select Energy. On July 26 and 29, 2002, the three major ratings agencies lowered the ratings of NRG to below investment grade. Concurrently, the potential, but now postponed, deactivation of NRG owned generating units in the state of Connecticut further called into question NRG's financial viability and the long term availability of power to serve CL&P's standard offer customers. On September 16, 2002, NRG announced its failure to meet a September 13, 2002 deadline by which it was to post collateral in excess of $1 billion and that it had not made payments on certain debt issues due on September 16, 2002. On November 22, 2002, an involuntary bankruptcy case was filed against NRG by seven former NRG executives. A settlement has been reached between NRG and the former executives and was scheduled for hearing on March 27, 2003. On March 20, 2003, CL&P filed an objection to dismissal of the involuntary case, which objection has subsequently been withdrawn. On April 10, 2003, the hearing originally scheduled for March 20, 2003 was held. The case is still pending. For further information on NRG related matters, see "Part I, Item 1 - Business - Rates and Electric Industry Restructuring - Connecticut," and Part I, Item 3 - Legal Proceedings," in NU's 2002 annual report on Form 10-K. CL&P - Station Service Matter CL&P has filed a petition for declaratory ruling with the DPUC seeking confirmation that under State law and regulation, station service has properly been billed to NRG and remains due and owing. In exchange for withdrawal of CL&P's objection to the dismissal of NRG's involuntary bankruptcy case, NRG has placed $4.2 million in an escrow account pending resolution of the station service issue. NRG has moved for dismissal of the DPUC petition. CL&P will be opposing NRG's motion. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Listing of Exhibits (NU) Exhibit No. Description ----------- ----------- 10.42.6 Amendment to Forsgren Employee Agreement, dated as of April 1, 2003 10.45.6 Amendment to Grise Employment Agreement, dated as of April 1, 2003 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 May 9, 2003 (a) Listing of Exhibits (CL&P) 99.1 Certification of Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power Company (the registrant) and John H. Forsgren, Executive Vice President and Chief Financial Officer of the registrant, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 9, 2003 (a) Listing of Exhibits (PSNH) 99.1 Certification of Cheryl W. Grise, Chief Executive Officer of Public Service Company of New Hampshire (the registrant) and John H. Forsgren, Executive Vice President and Chief Financial Officer of the registrant, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 9, 2003 (a) Listing of Exhibits (WMECO) 99.1 Certification of Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric Company (the registrant) and John H. Forsgren, Executive Vice President and Chief Financial Officer of the registrant, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated May 9, 2003 (b) Reports on Form 8-K: NU filed a current report on Form 8-K dated January 28, 2003, disclosing: o NU's earnings press release for the fourth quarter and full year 2002. SIGNATURE 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: May 9, 2003 By /s/ John H. Forsgren ----------- ---------------------------------- John H. Forsgren Vice Chairman, Executive Vice President and Chief Financial Officer (for the Registrant and as Principal Financial Officer) 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 registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 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: May 9, 2003 /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 registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 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: May 9, 2003 /s/ John H. Forsgren (Signature) John H. Forsgren Vice Chairman, Executive Vice President and Chief Financial Officer SIGNATURE 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: May 9, 2003 By /s/ John H. Forsgren ----------- ---------------------------------- John H. Forsgren Vice Chairman, Executive Vice President and Chief Financial Officer (for the Registrant and as Principal Financial Officer 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 registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 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: May 9, 2003 /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 The Connecticut Light and Power Company (the registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 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: May 9, 2003 /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer SIGNATURE 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: May 9, 2003 By /s/ John H. Forsgren ----------- ------------------------------ John H. Forsgren Executive Vice President and Chief Financial Officer (for the Registrant and as Principal Financial Officer) 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 registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 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: May 9, 2003 /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 Public Service Company of New Hampshire (the registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 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: May 9, 2003 /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer SIGNATURE 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: May 9, 2003 By /s/ John H. Forsgren ----------- ---------------------------------- John H. Forsgren Vice Chairman, Executive Vice President and Chief Financial Officer (for the Registrant and as Principal Financial Officer) 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 registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 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: May 9, 2003 /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 Western Massachusetts Electric Company (the registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 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: May 9, 2003 /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer