10-Q 1 june2003edgar.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 June 30, 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 July 31, 2003 ------------------------ ---------------------------- Northeast Utilities Common shares, $5.00 par value 127,097,444 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: NU COMPANIES OR SEGMENTS Boulos.................... E.S. Boulos Company CL&P...................... The Connecticut Light and Power Company CRC....................... CL&P Receivables Corporation HWP....................... Holyoke Water Power Company NGC....................... Northeast Generation Company NGS....................... Northeast Generation Services Company 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, 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 THIRD PARTIES CVEC...................... Connecticut Valley Electric Company MGT....................... Meriden Gas Turbines, LLC NEON...................... NEON Communications, Inc. NRG....................... NRG Energy, Inc. NRG-PM.................... NRG Power Marketing, Inc. PPL....................... PPL Corporation 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 Act, the.................. Public Act No. 03-135 CSC....................... Connecticut Siting Council CTA....................... Competitive Transition Assessment DIG....................... Derivative Implementation Group EITF...................... Emerging Issues Task Force EPS....................... Earnings per Share FASB...................... Financial Accounting Standards Board FMCC...................... Federally Mandated Congestion Costs GSC....................... Generation Services Charge IERM...................... Infrastructure Expansion Rate Mechanism Incentive Plan............ Northeast Utilities Incentive Plan IPPs...................... Independent Power Producers ISO-NE.................... New England Independent System Operator kWh....................... Kilowatt-hour LMP....................... Locational Marginal Pricing Moody's................... Moody's Investors Service 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 SBC....................... System Benefits Charge SCRC...................... Stranded Cost Recovery Charge SFAS...................... Statement of Financial Accounting Standards SMD....................... Standard Market Design TSO....................... Transitional Standard Offer 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 - June 30, 2003 and December 31, 2002.................... 2 Consolidated Statements of Income - Three Months and Six Months Ended June 30, 2003 and 2002................................. 4 Consolidated Statements of Cash Flows - Six Months Ended June 30, 2003 and 2002................ 5 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 6 Independent Accountants' Report............................. 33 Notes to Consolidated Financial Statements (unaudited - all companies).................................. 34 The Connecticut Light and Power Company and Subsidiaries Consolidated Balance Sheets - June 30, 2003 and December 31, 2002.................... 58 Consolidated Statements of Income - Three Months and Six Months Ended June 30, 2003 and 2002................................. 60 Consolidated Statements of Cash Flows - Six Months Ended June 30, 2003 and 2002................ 61 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 62 Public Service Company of New Hampshire and Subsidiaries Consolidated Balance Sheets - June 30, 2003 and December 31, 2002.................... 68 Consolidated Statements of Income - Three Months and Six Months Ended June 30, 2003 and 2002................................. 70 Consolidated Statements of Cash Flows - Six Months Ended June 30, 2003 and 2002................ 71 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 72 Western Massachusetts Electric Company and Subsidiary Consolidated Balance Sheets - June 30, 2003 and December 31, 2002.................... 78 Consolidated Statements of Income - Three Months and Six Months Ended June 30, 2003 and 2002................................. 80 Consolidated Statements of Cash Flows - Six Months Ended June 30, 2003 and 2002................ 81 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 82 Item 3. Quantitative and Qualitative Disclosures About Market Risk.......................... 85 Item 4. Controls and Procedures................................ 85 Part II. Other Information Item 1. Legal Proceedings...................................... 86 Item 4. Submission of Matters to a Vote of Security Holders............................... 89 Item 6. Exhibits and Reports on Form 8-K....................... 90 Signatures............................................................ 93 NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2003 2002 --------------- --------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash and cash equivalents $ 57,028 $ 54,678 Investments in securitizable assets 146,532 178,908 Receivables, net 626,435 767,089 Unbilled revenues 93,294 126,236 Fuel, materials and supplies, at average cost 124,060 119,853 Special deposits 87,982 43,261 Derivative assets 174,250 130,929 Prepayments and other 118,094 110,261 --------------- --------------- 1,427,675 1,531,215 --------------- --------------- Property, Plant and Equipment: Electric utility 5,305,546 5,141,951 Gas utility 697,130 679,055 Competitive energy 877,396 866,294 Other 209,993 205,115 --------------- --------------- 7,090,065 6,892,415 Less: Accumulated depreciation 2,542,716 2,484,613 --------------- --------------- 4,547,349 4,407,802 Construction work in progress 323,995 320,567 --------------- --------------- 4,871,344 4,728,369 --------------- --------------- Deferred Debits and Other Assets: Regulatory assets 2,993,305 3,076,095 Goodwill and other purchased intangible assets, net 344,063 345,867 Prepaid pension 344,496 328,890 Other 438,833 433,444 --------------- --------------- 4,120,697 4,184,296 --------------- --------------- Total Assets $ 10,419,716 $ 10,443,880 =============== =============== The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2003 2002 --------------- --------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to banks $ 63,000 $ 56,000 Long-term debt - current portion 58,345 56,906 Accounts payable 652,984 776,219 Accrued taxes 31,680 141,667 Accrued interest 41,153 40,597 Derivative liabilities 107,278 63,900 Other 228,459 208,680 --------------- --------------- 1,182,899 1,343,969 --------------- --------------- Rate Reduction Bonds 1,816,998 1,899,312 --------------- --------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 1,407,194 1,436,507 Accumulated deferred investment tax credits 104,562 106,471 Deferred contractual obligations 334,883 354,469 Other 777,003 689,287 --------------- --------------- 2,623,642 2,586,734 --------------- --------------- Capitalization: Long-Term Debt 2,465,483 2,287,144 --------------- --------------- Preferred Stock - Nonredeemable 116,200 116,200 --------------- --------------- Common Shareholders' Equity: Common shares, $5 par value - authorized 225,000,000 shares; 149,916,375 shares issued and 126,934,753 shares outstanding in 2003 and 149,375,847 shares issued and 127,562,031 shares outstanding in 2002 749,582 746,879 Capital surplus, paid in 1,105,241 1,108,338 Deferred contribution plan - employee stock ownership plan (80,170) (87,746) Retained earnings 798,796 765,611 Accumulated other comprehensive income 1,789 14,927 Treasury stock, 19,517,497 shares in 2003 and 18,022,415 shares in 2002 (360,744) (337,488) --------------- --------------- Common Shareholders' Equity 2,214,494 2,210,521 --------------- --------------- Total Capitalization 4,796,177 4,613,865 --------------- --------------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization $ 10,419,716 $ 10,443,880 =============== =============== The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Six Months Ended June 30, June 30, ------------------------------ ------------------------------ 2003 2002 2003 2002 -------------- -------------- -------------- -------------- (Thousands of Dollars, except share information) Operating Revenues $ 1,457,541 $ 1,141,928 $ 3,145,978 $ 2,426,389 -------------- -------------- -------------- -------------- Operating Expenses: Operation - Fuel, purchased and net interchange power 893,935 627,062 1,963,230 1,353,677 Other 231,278 198,724 420,550 396,755 Maintenance 68,280 73,449 114,172 125,761 Depreciation 50,692 53,596 100,165 105,811 Amortization 21,497 5,710 78,796 25,954 Amortization of rate reduction bonds 35,303 34,476 74,503 80,636 Taxes other than income taxes 51,460 54,860 125,434 129,458 -------------- -------------- -------------- -------------- Total operating expenses 1,352,445 1,047,877 2,876,850 2,218,052 -------------- -------------- -------------- -------------- Operating Income 105,096 94,051 269,128 208,337 Interest Expense: Interest on long-term debt 28,546 34,391 61,486 67,363 Interest on rate reduction bonds 27,364 29,226 55,225 58,788 Other interest 3,617 5,391 6,361 9,744 -------------- -------------- -------------- -------------- Interest expense, net 59,527 69,008 123,072 135,895 -------------- -------------- -------------- -------------- Other Income/(Loss), Net 754 1,653 1,330 (12,344) -------------- -------------- -------------- -------------- Income Before Income Tax Expense/(Benefit) 46,323 26,696 147,386 60,098 Income Tax Expense/(Benefit) 18,065 (3,550) 57,534 9,820 -------------- -------------- -------------- -------------- Income Before Preferred Dividends of Subsidiaries 28,258 30,246 89,852 50,278 Preferred Dividends of Subsidiaries 1,389 1,389 2,779 2,779 -------------- -------------- -------------- -------------- Net Income $ 26,869 $ 28,857 $ 87,073 $ 47,499 ============== ============== ============== ============== Basic and Fully Diluted Earnings Per Common Share $ 0.21 $ 0.22 $ 0.69 $ 0.37 ============== ============== ============== ============== Basic Common Shares Outstanding (average) 126,747,117 129,677,793 126,880,397 129,590,899 ============== ============== ============== ============== Fully Diluted Common Shares Outstanding (average) 126,860,208 129,993,412 126,982,903 129,871,495 ============== ============== ============== ============== The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Six Months Ended June 30, ------------------------------- 2003 2002 ------------- ------------- (Thousands of Dollars) Operating Activities: Income before preferred dividends of subsidiaries $ 89,852 $ 50,278 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation 100,165 105,811 Deferred income taxes and investment tax credits, net (10,383) (53,089) Amortization 78,796 25,954 Amortization of rate reduction bonds 74,503 80,636 Net (deferral)/amortization of recoverable energy costs (9,441) 20,290 Prepaid pension (15,606) (35,050) Net other (uses)/sources of cash (5,830) 88,332 Changes in working capital: Receivables and unbilled revenues, net 173,596 7,116 Fuel, materials and supplies (4,208) (12,217) Accounts payable (123,235) 32,255 Accrued taxes (109,987) 4,707 Investments in securitizable assets 32,376 7,482 Other working capital (excludes cash) (49,822) 24,722 ---------- ---------- Net cash flows provided by operating activities 220,776 347,227 ---------- ---------- Investing Activities: Investments in plant: Electric, gas and other utility plant (228,545) (198,248) Competitive energy assets (8,183) (13,945) Nuclear fuel - (295) ---------- ---------- Cash flows used for investments in plant (236,728) (212,488) Buyout/buydown of IPP contracts (20,437) - Other investment activities, net 5,644 (52,147) ---------- ---------- Net cash flows used in investing activities (251,521) (264,635) ---------- ---------- Financing Activities: Issuance of common shares 7,463 5,965 Repurchase of common shares (23,209) (18,250) Issuance of long-term debt 194,851 263,000 Issuance of rate reduction bonds - 50,000 Retirement of rate reduction bonds (82,314) (67,160) Net increase/(decrease) in short-term debt 7,000 (500) Reacquisitions and retirements of long-term debt (28,688) (282,766) Cash dividends on preferred stock (2,779) (2,779) Cash dividends on common shares (34,886) (32,379) Other financing activities, net (4,343) (358) ---------- ---------- Net cash flows provided by/(used in) financing activities 33,095 (85,227) ---------- ---------- Net increase/(decrease) in cash and cash equivalents 2,350 (2,635) Cash and cash equivalents - beginning of period 54,678 96,658 ---------- ---------- Cash and cash equivalents - end of period $ 57,028 $ 94,023 ========== ========== The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES Management's Discussion and Analysis of Financial Condition and Results of Operations This discussion should be read in conjunction with the consolidated financial statements and footnotes in this Form 10-Q, the First Quarter 2003 Form 10-Q, the NU 2002 Form 10-K, and the current report on Form 8-K dated May 14, 2003. FINANCIAL CONDITION Overview -------- Consolidated: Northeast Utilities (NU or the company) earned $26.9 million, or $0.21 per share, in the second quarter of 2003, compared with net income of $28.9 million, or $0.22 per share, in the second quarter of 2002. For the first six months of 2003, NU earned $87.1 million, or $0.69 per share, compared with net income of $47.5 million, or $0.37 per share, for the first six months of 2002. The results for the first six months of 2002 included after-tax write-downs totaling $10 million, or $0.08 per share, related to NU's investments in NEON Communications, Inc. (NEON) and Acumentrics Corporation (Acumentrics) and approximately $13 million of investment tax credits related to divested generation reflected by Western Massachusetts Electric Company (WMECO) as a result of a regulatory decision. The results for the first six months of 2003 did not include any similar write-downs or investment tax credits. All per share amounts are reported on a fully diluted basis. As more fully discussed below, the reduction of $2 million in second quarter net income in 2003 as compared with the same period of 2002 was due to a combination of factors, including lower Utility Group net income in the second quarter of 2003 as compared to the same period of 2002, offset by significantly improved results at NU Enterprises. A turnaround in the operations of NU Enterprises resulted in a $46.8 million increase in net income for the first six months of 2003 as compared with the same period of 2002. Net income generated from the Utility Group decreased $21.2 million in the first six months of 2003 as compared with the same period of 2002. Net income for the six months ended June 30, 2002 also included the impacts of the aforementioned after-tax write downs and investment tax credits. NU's earnings per share also benefited modestly from its share repurchase program. NU repurchased approximately 1.6 million shares at an average price of $14.14 in the first quarter of 2003. There were no share repurchases in the second quarter of 2003. NU had approximately 126.9 million shares outstanding at June 30, 2003. In May 2003, the NU Board of Trustees authorized the repurchase of up to 10 million additional shares through July 1, 2005. NU's revenues during the first six months of 2003 increased to $3.1 billion from $2.4 billion in the same period of 2002. The increase in revenues is partially due to increases in electric and firm natural gas sales in 2003 as compared to 2002 and higher wholesale marketing revenues at NU Enterprises. Utility Group: Utility Group net income was lower due to the absence of approximately $13 million of investment tax credits that were reflected in the second quarter of 2002 at WMECO, as well as lower pension income and the loss of net income related to the Seabrook nuclear unit, which was sold on November 1, 2002. Lower pension income and the sale of Seabrook resulted in approximately a $9 million and a $5 million decrease, respectively, in net income in 2003 as compared to 2002. The Utility Group benefited from higher sales volumes. Overall, regulated retail electric sales increased 0.6 percent in the second quarter of 2003 and 4.9 percent in the first half of 2003, compared with the same periods of 2002. Firm natural gas sales at Yankee Gas Services Company (Yankee Gas) increased 4.1 percent in the second quarter of 2003 and 13.6 percent in the first half of 2003, compared with the same periods of 2002. Higher sales volumes resulted in approximately a $10 million increase in net income in 2003 as compared to 2002. Earnings before preferred dividends at The Connecticut Light and Power Company (CL&P) totaled $6.1 million in the second quarter of 2003 and $32.8 million in the first half of 2003, compared with $11.4 million in the second quarter of 2002 and $33.1 million in the first half of 2002. The lower second quarter net income resulted from higher operation and maintenance (O&M) expense levels due in part to lower pension income and lower earnings on regulatory assets, offset by increased retail sales. The second quarter of 2003 was also modestly impacted by the effect of an earnings sharing formula under which half of CL&P's net income in excess of a 10.3 percent return on equity is credited to customers in the form of additional amortization of regulatory assets. Public Service Company of New Hampshire (PSNH) earned $11.1 million in the second quarter of 2003 and $21.9 million in the first half of 2003, compared with $15.2 million in the second quarter of 2002 and $27 million in the first half of 2002. Lower PSNH net income resulted from higher pension expense and a lower level of regulatory assets earning a return, primarily due to the sale of Seabrook on November 1, 2002. The reduction in net regulatory assets will continue to negatively affect PSNH's 2003 to 2002 net income comparisons. Additionally, second quarter 2002 net income includes $4.2 million for the positive resolution of certain contingencies related to a PSNH regulatory proceeding. Net income at WMECO was $2.6 million in the second quarter of 2003 and $8.7 million in the first half of 2003, compared with $15.3 million in the second quarter of 2002 and $22.2 million in the first half of 2002. The primary reason for the net income decline was the absence of approximately $13 million of investment tax credits related to divested generation that WMECO reflected in the second quarter of 2002 as a result of a regulatory decision. Yankee Energy System, Inc. (Yankee) lost $3 million in the second quarter of 2003 and earned $12.2 million in the first half of 2003, compared with a loss of $0.5 million in the second quarter of 2002 and net income of $12.1 million in the first half of 2002. Yankee benefited from colder temperatures, but was negatively affected by lower pension income and a change in the estimate of unbilled revenues. NU expects that pension income will decline from approximately $73 million in 2002 to approximately $32 million in 2003. Of the $41 million decline, approximately 70 percent ($29 million) will reduce pretax earnings. The remaining 30 percent ($12 million) relates to employees working on capital projects and will be reflected as higher capital expenditures. The $29 million increase in operating expenses is reflected evenly throughout the year resulting in a decline of approximately $4.4 million in net income per quarter during 2003. NU Enterprises: NU Enterprises, Inc. is the parent company of Select Energy, Inc. (Select Energy), Northeast Generation Company (NGC), Select Energy Services, Inc. (SESI), Northeast Generation Services Company (NGS), and their respective subsidiaries, and Woods Network Services, Inc., all of which are collectively referred to as "NU Enterprises." Holyoke Water Power Company (HWP) is also included in NU Enterprises. NU Enterprises earned $11.9 million in the second quarter of 2003 and $17.1 million in the first half of 2003, compared with a loss of $9.2 million in the second quarter of 2002 and a loss of $29.7 million in the first half of 2002. NU Enterprises' net income improved due to improved results in the wholesale marketing group, the absence of energy trading losses, better performance in the retail energy and services businesses, and increased hydroelectric plant output in the first six months of 2003 compared with the same period of 2002. Select Energy's wholesale marketing group includes wholesale origination, portfolio management and the operation of more than 1,400 megawatts (MW) of pumped storage, hydroelectric and coal-fired generation assets. The wholesale marketing group earned $12.1 million in the second quarter of 2003 and $19.4 million in the first half of 2003, compared with $2.3 million in the second quarter of 2002 and $6.4 million in the first half of 2002. The wholesale marketing group's second quarter of 2003 results benefited from the termination of contracts which had the impact of accelerating $2 million of profits from the second half of 2003 and $0.3 million of profits from 2004 into the second quarter of 2003. With precipitation returning to more normal levels, output has increased at NGC's Connecticut and Massachusetts conventional hydroelectric plants by approximately 70,000 megawatt-hours in the first six months of 2003 or by approximately 22 percent, compared to the first six months of 2002. This resulted in $1.6 million of additional net income in 2003 as compared to 2002. Trading activities, which are part of risk management for the wholesale marketing group, earned $0.5 million in the second quarter of 2003 and were essentially breakeven in the first half of 2003 compared with losses of $7.5 million in the second quarter of 2002 and $17.6 million in the first half of 2002. Trading activities have been significantly reduced in size over the past year. The retail business lost $2.1 million in the second quarter of 2003 and $4.2 million in the first half of 2003 compared with losses of $4.4 million in the second quarter of 2002 and $18.6 million in the first half of 2002. The 2003 improved retail results are primarily due to improved management of gas retail contracts along with improved margins and growth in retail electric sales. The energy services businesses earned $1.4 million in the second quarter of 2003 and $1.9 million in the first half of 2003 compared with earnings of $0.4 million in the second quarter of 2002 and $0.1 million in the first half of 2002. Future Outlook -------------- Consolidated: NU continues to project net income of between $1.10 per share and $1.30 per share in 2003. Despite a strong first half of 2003, management believes that a combination of more seasonable weather, lower pension income, and the absence of Seabrook-related and other regulatory asset based earnings will result in lower quarterly results in the third and fourth quarters of 2003 than those reported by NU in the second half of 2002. Utility Group: The projected net income range of between $1.10 per share and $1.30 per share continues to include net income of between $1.05 per share and $1.15 per share at the Utility Group. NU Enterprises: NU continues to project net income of between $0.15 per share and $0.25 per share at NU Enterprises with the objective of finishing 2003 in the upper end of that range. This estimate assumes that Select Energy will not bear any of the costs associated with the March 1, 2003 implementation of standard market design (SMD) and locational marginal pricing (LMP) in New England, as this implementation affects Select Energy's standard offer supply contract with CL&P. From March 1, 2003 through June 30, 2003, pre-tax LMP costs related to Select Energy's contract with CL&P totaled approximately $35 million, and by the end of 2003, those costs are estimated to total between $85 million and $90 million. The issue of responsibility for LMP costs associated with all three of CL&P's standard offer supply contracts is now before the Federal Energy Regulatory Commission (FERC), and a decision is expected in early 2004. 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 as NU had $57 million of cash and cash equivalents on hand at June 30, 2003 while NU parent had $180.9 million invested in the NU system Money Pool. The Utility Group and NU Enterprises have $192.4 million and $22.8 million of borrowings from the NU system Money Pool, respectively, while other NU companies have $34.3 million invested in the NU system Money Pool. NU's liquidity was enhanced on June 3, 2003, when NU issued $150 million of five-year notes at an interest rate of 3.3 percent. The proceeds from the issuance of these notes were used to refinance Select Energy's short-term debt to NU Parent and to provide short- term financing to Select Energy. NU's net cash flows from operating activities decreased to $220.8 million in the first six months of 2003 from $347.2 million in the first six months of 2002. The decrease in cash flows from operating activities resulted from the payment of $190.6 million of taxes, primarily on the gain on the sale of Seabrook, combined with decreases in other working capital items. Working capital items were impacted by reduced levels of accounts receivable and accounts payable, primarily at Select Energy. These decreases were partially offset by a $39.6 million increase in income before preferred dividends of subsidiaries. NU's capital expenditures totaled $236.7 million in the first six months of 2003 compared to $212.5 million in the first six months of 2002. NU currently projects capital expenditures of approximately $600 million in 2003. In the first six months of 2003, NU also repaid $28.7 million of long- term debt and $82.3 million of rate reduction bonds. The level of common dividends totaled $34.9 million in the first six months of 2003, compared with $32.4 million in the first six months of 2002. The increase in the level of common dividends resulted from NU paying two $0.1375 per share quarterly common dividends in the first six months of 2003 compared to two $0.125 per share quarterly dividends in the first six months of 2002. On May 13, 2003, the NU Board of Trustees declared a dividend of $0.15 per share payable on September 30, 2003, to shareholders of record on September 1, 2003. The 9.1 percent dividend increase was consistent with management's expectation to continue to increase the dividend level annually, 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 the second quarter, NU's credit ratings were placed on a negative outlook by Moody's Investors Service (Moody's) and Fitch Ratings. CL&P has also been put on a negative outlook by Moody's. The change in outlook from stable to negative was the result of higher forecasted capital spending at CL&P and efforts by NRG Energy, Inc. (NRG) to terminate its standard offer service contract with CL&P. These changes in outlook had no material effect on NU's liquidity, costs, or access to capital. For more information on NRG see the "NRG Exposures" section of this Management's Discussion and Analysis and Note 4B, "Commitments and Contingencies - NRG Energy, Inc. Exposures," to the consolidated financial statements. Utility Group: At June 30, 2003, NU's Utility Group had no borrowings outstanding on its $300 million revolving credit line. This credit line matures on November 11, 2003, and management anticipates extending this credit line. On July 9, 2003, CL&P renewed an agreement for one year under which it can access up to $100 million by selling certain of its accounts receivable and unbilled revenues. At June 30, 2003, CL&P had $50 million of accounts receivable and unbilled revenues sold under this arrangement. For more information regarding CL&P's accounts receivable facility, see Note 1F, "Sale of Customer Receivables," to the consolidated financial statements. Through June 30, 2003, CL&P has recovered approximately $30 million of incremental LMP costs from its customers and has withheld payment of these incremental LMP costs from its standard offer service suppliers. This has positively impacted CL&P's liquidity. In July 2003, CL&P began depositing these recoveries into an escrow account. Accordingly, further recovery of these costs will not impact CL&P's liquidity. When the issue of responsibility for incremental LMP costs is resolved, which is expected to be in early 2004, there will be a negative impact on CL&P's liquidity for the amounts recovered but not deposited into the escrow account, as these amounts are paid to standard offer service suppliers or returned to customers. Effective May 31, 2003, PSNH bought out the power purchase obligations of 14 small independently owned hydroelectric plants in New Hampshire for $20.4 million, which was paid from cash flows from operations. The buy out payments have been recorded as regulatory assets, and will be recovered, including a return, over the remaining term of the initial contractual arrangements as Part 2 stranded costs. On June 27, 2003, the Massachusetts Department of Telecommunications and Energy (DTE) issued an order allowing WMECO to issue up to $57.5 million of long-term securities on or before December 31, 2003 to refinance short-term debt and cover issuance costs. WMECO is expected to issue that debt in the second half of 2003. On July 1, 2003, Standard & Poor's initiated a BBB+ rating on Yankee Gas. On July 25, 2003, Moody's initiated a Baa1 rating on Yankee Gas. Management secured the rating to enhance Yankee Gas' financial relationships with its gas suppliers and in anticipation of issuing new debt to finance the construction of a liquefied natural gas storage facility and build out of its gas distribution system. NU Enterprises: NU Enterprises had $63 million in borrowings and $10.2 million in letters of credit outstanding on NU parent's $350 million revolving credit line. This credit line matures on November 11, 2003, and management anticipates extending this credit line. NU Enterprises effectively refinanced a significant portion of its short-term debt from associated companies into long-term advances from NU parent as a result of the $150 million, five-year notes issued by NU in June 2003. Select Energy has billed CL&P for incremental LMP costs in the amount of approximately $35 million. Select Energy has not received any amounts from CL&P, which has negatively impacted Select Energy's liquidity. This negative impact is expected to continue to increase through the resolution of the incremental LMP cost issue. Impacts of Standard Market Design --------------------------------- On March 1, 2003, the New England Independent System Operator (ISO-NE) implemented SMD. As part of SMD, LMP is now 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. The calculation of line losses is now based on an economic formula. Prior to March 1, 2003, those costs were spread across virtually all New England electric customers based on engineering data of actual line losses experienced. 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 five other New England states. The three components of the LMP for each zone are 1) an energy cost, 2) congestion costs and 3) line loss charges assigned to the zone. LMP is increasing costs in zones that have inadequate or less cost-efficient generation and/or transmission constraints, such as Connecticut, and decreasing costs in zones that have sufficient or even excess generation, such as Maine. The implementation of SMD has impacted 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. If high loads, transmission constraints and inadequate generation are experienced, Connecticut could experience significant additional congestion costs under SMD. ISO-NE estimated that the majority of congestion and its costs would be in Connecticut, where approximately 80 percent is expected to be paid by CL&P. CL&P began incurring these costs on March 1, 2003. For the four-month period from March 1, 2003 through June 30, 2003, incremental LMP costs have totaled approximately $62 million. Approximately 80 percent of these incremental costs (approximately $47 million, or approximately $12.5 million per month on average) were associated with line losses, with monthly line losses ranging from $9.9 million to $14.1 million. Management expects comparable monthly line loss charges for the remainder of 2003. The LMP costs also include approximately $13 million related to congestion costs for the four-month period with monthly congestion costs ranging from $0.2 million to $6.1 million. The remaining $2 million of incremental LMP costs incurred through June 30, 2003 related to energy price differences between LMP zones. In July 2003, incremental LMP costs amounted to approximately $25 million, including $16.6 million of line loss charges and $8.4 million of congestion costs. As a result of cooler than average temperatures to date, the congestion cost component of LMP has not been as significant as originally anticipated. However, line loss charges have been significant. Management currently expects that incremental total LMP costs for CL&P for all of 2003 will be between $170 million and $180 million. Actual incremental LMP costs could be significantly higher if congestion and line loss charges are greater than anticipated as a result of unusual weather and other factors management cannot predict. 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 and/or line losses. Management believes that under the legal interpretation of the terms of its standard offer service contracts with its standard offer suppliers, the incremental costs associated with line 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 $62 million of incremental LMP costs incurred from March 1, 2003 through June 30, 2003 were recorded as recoverable energy costs, and approximately $30 million has been billed to customers and reflected in revenues. The remaining balance is included in recoverable energy costs, which collectively is a component of regulatory assets. 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 should be paid for by CL&P's customers. Accordingly, CL&P filed for and has received approval on May 1, 2003, for their recovery, subject to refund. CL&P began recovery of the March 2003 LMP costs in its May 2003 billings and continues to bill LMP costs in its June and July 2003 billings, collecting April and May 2003 LMP costs, respectively. The Connecticut Department of Public Utility Control's (DPUC) decision regarding recovery of incremental LMP costs 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. The DPUC required CL&P to obtain surety bonds for the $31.1 million of March 2003 and April 2003 incremental LMP costs. These surety bonds are guaranteed by NU parent. Incremental LMP costs beginning with the May 2003 amounts which were billed to customers in July will be deposited in an escrow account as billings of these amounts are collected. In response to the DPUC decision of May 1, 2003, CL&P has filed for a declaratory judgment from the FERC to determine whether CL&P's standard offer service suppliers are responsible for incremental LMP costs. Additionally, CL&P has withheld payment of all $62 million of incremental LMP costs to its standard offer service suppliers, pending resolution of this matter. Final briefs before the FERC are due in November 2003, and a decision from the FERC is expected in early 2004. 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 regulated electric distribution companies were responsible for approximately 25 percent of these costs. Effective with the March 1, 2003 implementation of SMD, RMR costs were allocated to the load zone in which the RMR unit is located. At present, the only load zone that is experiencing an RMR cost increase in which NU's regulated electric distribution companies operate is Connecticut. Reliability costs have been previously approved for recovery by the DPUC in generation service charge costs, which were reviewed by the DPUC in CL&P's 2001 Competitive Transition Assessment (CTA) reconciliation filing. RMR costs incurred during 2002 totaling $7.8 million 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. For the six-month period ended June 30, 2003, CL&P incurred $17.9 million of RMR costs. As part of the SMD implementation on March 1, 2003, ISO-NE now calculates line loss charges based on an economic formula and not on actual losses experienced. To date, ISO-NE has not filed its methodology for determining line loss charges with the FERC, and CL&P has been unable to verify the validity or accuracy of ISO-NE's billings. Accordingly, on July 23, 2003, CL&P filed a complaint with the FERC requesting that ISO-NE provide its methodology for determining such charges. Interventions and answers are due on August 12, 2003. Management cannot predict the outcome or effect of this proceeding on CL&P. 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. The increase in RMR costs as a result of PPL's and NRG's requests has not been significant. At this time, management cannot determine CL&P's exposure to RMR costs or the impact on incremental LMP costs as a result of these requests. On July 25, 2003, CL&P filed with the DPUC a request for approval of a formal recovery mechanism that would allow for the tracking and recovery of all Federally Mandated Congestion Costs (FMCC) as outlined in Connecticut Public Act No. 03-135 (the Act). The major cost components of FMCC are congestion costs, line losses and RMR costs. It is anticipated that the DPUC will open a formal review of CL&P's proposal with a final resolution on the matter expected by the end of 2003. 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 six months ended June 30, 2003 would be reduced by approximately $35 million. Management currently expects Select Energy's share of incremental LMP costs for 2003 to be between $85 million and $90 million, depending on the level of line losses and congestion costs experienced. Management believes that these costs are not contractually Select Energy's responsibility, but will assess the collectibility of Select Energy's accounts receivable from CL&P based on developments at the FERC. Select Energy's standard offer service contract with CL&P expires on December 31, 2003. NU Enterprises' and NU's 2003 net income estimates do not include incremental LMP costs. SMD impacted the delivery points in many wholesale marketing contracts and in some trading contracts. At June 30, 2003, Select Energy has resolved most of the suppliers' choice delivery points in contracts, and this issue is not expected to materially affect Select Energy. For information regarding commitments and contingencies related to the accounting for the implementation of SMD, see Note 4A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements. NRG Exposures ------------- Certain subsidiaries of NU have entered into various transactions with certain subsidiaries of NRG. On May 14, 2003, NRG filed a voluntary bankruptcy petition. NRG-related exposures to certain subsidiaries of NU as a result of these transactions are as follows: Standard Offer Service Contract: NRG has a contract with CL&P to supply 45 percent of CL&P's standard offer service load through December 31, 2003. NRG attempted to terminate the contract with CL&P, but the FERC ordered NRG to continue serving CL&P under its standard offer supplier contract. Subsequently, NRG received a temporary order from the United States District Court and on June 12, 2003 stopped serving CL&P with standard offer supply. NRG was ultimately ordered by the FERC to resume serving CL&P's standard offer service load and did so on July 2, 2003. During the period NRG did not serve CL&P under its standard offer service contract, CL&P purchased power from the spot market at prices in excess of NRG's contract price. This excess amounted to $7.9 million and was recorded as recoverable energy costs, which CL&P began billing to customers August 1, 2003. Management will pursue recovery of these costs from NRG, and if these costs are ultimately collected from NRG, then CL&P would refund any portion of the $7.9 million previously paid by them. Station Service: CL&P provides NRG with station service, which is electric service when a generator is off-line or unable to satisfy its station service requirements, at DPUC-approved retail rates. NRG objects to being billed at retail rates and has refused to pay CL&P. Management will continue to pursue recovery from NRG of the station service balance, including $4.2 million NRG placed in an escrow account related to this matter. During the second quarter of 2003 as a result of NRG's bankruptcy, the amount due from NRG in excess of the escrow amount was reserved. Management expects to continue to seek recovery from NRG; however, management believes that amounts not collected from NRG are ultimately recoverable from CL&P's customers. Therefore, a regulatory asset of $10.6 million was recorded. Through June 30, 2003, legal costs incurred by CL&P related to NRG's bankruptcy amounted to $0.4 million. This amount has been recorded as a regulatory asset, and NU will continue to defer these legal costs as they are incurred. Pre-March 1, 2003 Congestion Charges: In November 2001, CL&P filed suit against NRG in Connecticut Superior Court seeking judgment for unpaid pre- March 1, 2003, congestion charges under its standard offer supply contract. On August 5, 2002, CL&P withheld the then unpaid congestion charges from payments due to NRG for standard offer service. CL&P has continued to withhold these charges on a monthly basis, netting the standard offer supplier payments with the congestion costs. The total amount of congestion costs withheld from NRG is $27.5 million. If it is ultimately concluded that CL&P is responsible for pre-March 1, 2003 congestion costs, management believes CL&P would be allowed to recover these costs from its customers. Meriden Gas Turbines LLC: Yankee Gas, E.S. Boulos Company (Boulos), which is a subsidiary of NGS, and CL&P have exposures to Meriden Gas Turbines LLC (MGT), an NRG subsidiary that is not included in NRG's voluntary bankruptcy petition. Yankee Gas made capital expenditures in excess of $16 million for a natural gas pipeline to a generating plant that MGT was constructing. Yankee Gas drew down on a $16 million letter of credit when MGT indicated that it was abandoning construction of the generating plant. NRG has contested the draw down on the letter of credit. Yankee Gas has a counterclaim pending against MGT to recover additional monies in accordance with the contract that are in excess of the $16 million letter of credit. Boulos has a 50 percent interest in a joint venture that was building switchyards for the MGT generating plant. Boulos is owed $2.6 million as a result of Boulos' work through the joint venture. The joint venture has commenced a legal proceeding against the general contractor to collect what is owed. The joint venture is also a party to a mechanics lien foreclosure action in which one of its subcontractors is attempting to foreclose upon a mechanics lien filed on the MGT generating plant. MGT also currently owes CL&P $0.5 million for work on the South Kensington switching station, which was to be the interconnection point for the MGT generating plant. Management does not expect that the resolution of the aforementioned MGT disputes will have a material adverse effect on the financial condition or results of operations of NU and its subsidiaries. Management cannot predict the resolution of the exposures to NRG at this time. For further information regarding these NRG exposures, see Note 4B, "Commitments and Contingencies - NRG Energy, Inc. Exposures," to the consolidated financial statements and Part II, Item 1, "Legal Proceedings," included in this combined report on Form 10-Q. NU Enterprises -------------- Subsidiaries: NU Enterprises, Inc. is the parent company of Select Energy, NGC, SESI, NGS, and their respective subsidiaries, and Woods Network Services, Inc., which are collectively referred to as "NU Enterprises." 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 includes 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: Financial performance at NU Enterprises improved significantly in the first half of 2003 compared to 2002. The wholesale marketing business obtained several new contracts since the first quarter of 2003. Select Energy has been awarded electric supply contracts by the Maine Public Utilities Commission to provide standard offer service to large commercial and industrial customers of Central Maine Power Company and Bangor Hydro Electric Company. Approximately 160 MW will be provided, and revenues are expected to total approximately $30 million during the contract period, which begins on September 1, 2003 and runs through February 2004. Over 400 MW of default service with NSTAR subsidiaries Boston Edison Company, Commonwealth Electric Light and Cambridge Electric Light began July 1, 2003 and runs through June 30, 2004. Revenues are expected to exceed $100 million. Also, on July 1, 2003, Select Energy began serving under a contract with affiliate WMECO to supply a portion of its default service through December 31, 2003. A contract to supply default service with Fitchburg Gas and Electric Company began June 1, 2003 and runs through November 30, 2003. Both contracts serve commercial and industrial customers, and Select Energy expects approximately $6 million in combined revenues from those transactions. Management currently believes that the wholesale marketing business will generate the wholesale origination margins required to support NU Enterprises' 2003 net income estimate. Essentially all of the wholesale origination margins needed to support NU Enterprises' 2003 net income estimate has been contracted by June 30, 2003. To meet the net income estimate, the wholesale marketing business will need to successfully manage its portfolio of contracts to retain the estimated origination margins. The retail marketing business also improved its financial performance in 2003 compared to 2002. At June 30, 2003, approximately 50 percent of the retail origination margins needed to cover projected costs and achieve break-even performance in 2003 has been contracted. Retail gas customers have continued to be 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. Although market conditions are beginning to improve, management currently believes that the retail marketing business line will be below its net income target for 2003. The retail marketing business will have to be successfully managed to realize the estimated margin for the contracts in its retail marketing portfolio. Intercompany Transactions: CL&P's standard offer service purchases from Select Energy represented approximately $280 million of total NU Enterprises' revenues for the first six months of 2003. Other transactions between CL&P and Select Energy amounted to approximately $69 million in revenues for Select Energy in the first six months of 2003. Select Energy will continue to provide standard offer service for its affiliate WMECO through December 31, 2003. WMECO's purchases from Select Energy represented approximately $68 million of total NU Enterprises' revenues in the first six months 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 Select Energy is organized by management to address the market, credit and operational exposures arising from the company's business lines: 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 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 June 30, 2003, the wholesale marketing portfolio, which includes the CL&P standard offer service contract that extends through 2003 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 may be significant volatility in the energy commodities markets that may 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 Within 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 net income. At June 30, 2003, Select Energy had trading derivative assets of $141 million and trading derivative liabilities of $96 million on a counterparty-by- counterparty basis, for a net positive position of $45 million for 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 business 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 June 30, 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; 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 for which fair value is determined based on a model. This contract expires in 2006 and the last year of the contract, including an option component, had a fair value of $4 million at June 30, 2003. Broker quotes for electricity are available through the year 2005, and models are generally used for the years 2006 and thereafter. Broker quotes for natural gas are available through 2013. Select Energy has sourced substantially all of the trading contracts that have maturities in excess of four years. Because these contracts are sourced, changes in the value of these contracts due to changes in commodity prices are not expected to impact Select Energy's earnings. 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 June 30, 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 June 30, 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 $(3.0) $ 0.1 $ - $(2.9) Prices provided by external sources 11.0 14.4 18.5 43.9 Prices based on models or other valuation methods - 4.0 - 4.0 ------------------------------------------------------------------------------- Totals $ 8.0 $18.5 $18.5 $45.0 ------------------------------------------------------------------------------- The fair value of energy trading contracts decreased by $0.8 million from $45.8 million at March 31, 2003 to $45 million at June 30, 2003. Contracts realized or otherwise settled during the period of $2.2 million includes the termination of a contract with a positive fair value at March 31, 2003 of $5.7 million. The change in fair value attributable to changes in valuation techniques and assumptions is due to a change in the discount rate management uses to determine the fair value of trading contracts. In the second quarter of 2003, the rate was changed from a fixed rate of 5 percent to a market-based LIBOR discount rate. ------------------------------------------------------------------------------- Total Fair Value ------------------------------------------------------------------------------- Three Months Ended Six Months Ended (Millions of Dollars) June 30, 2003 June 30, 2003 ------------------------------------------------------------------------------- Fair value of trading contracts outstanding at the beginning of the period $45.8 $41.0 Contracts realized or otherwise (2.2) (5.0) settled during the period Fair value of new contracts when entered into during the period - - Changes in fair value attributable to changes in valuation techniques and assumptions 2.3 2.3 Changes in fair value of contracts (0.9) 6.7 ------------------------------------------------------------------------------- Fair value of trading contracts outstanding at the end of the period $45.0 $45.0 ------------------------------------------------------------------------------- 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 estimate the fair value of its long-term wholesale marketing energy contracts. Changes are occurring in the administration of transmission systems and system operators 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 advances, letters of credit, and parent guarantees), and the use of standardized agreements that 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 June 30, 2003, approximately 80 percent of Select Energy's counterparty credit exposure to wholesale marketing and trading counterparties was cash collateralized or rated BBB- or better. Another three percent of the counterparty credit exposure was to unrated municipalities. Asset Concentrations: At June 30, 2003, positions with three counterparties collectively represented approximately $75 million, or 53 percent, of the $141 million trading derivative assets. The largest counterparty's position is secured with letters of credit, cash collateral, and investment grade parent guarantees. Select Energy holds an investment grade parent guarantee on the second counterparty's position. The third counterparty is an unrated generation entity as to which Select Energy does not hold collateral or guarantees. None of the other counterparties represented more than 10 percent of trading derivative assets. Exposures to Bankruptcies: Select Energy does not have a significant level of exposure to Mirant Americas Energy Marketing, LP, NRG, or PG&E Energy Trading - Power, L.P., all of which are in bankruptcy at this time. At this time, Select Energy does not have significant credit exposure to other entities that are not in bankruptcy but have below investment grade ratings. 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 $274 million of collateral or letters of credit to various unaffiliated counterparties and approximately $82 million to several independent system operators and unaffiliated local distribution companies, which management believes NU would currently be able to provide. NU's credit ratings outlooks are currently stable or negative, but 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: On July 14, 2003, the Connecticut Siting Council (CSC) approved a 345,000 volt transmission line project from Bethel, Connecticut to Norwalk, Connecticut, proposed in October 2001 by CL&P. The configuration of the new transmission line, enhancements to an existing 115,000 volt transmission line, and work in related substations are estimated to cost approximately $200 million. The line would help address the difficulties in serving the load in southwest Connecticut that creates high LMP costs in Connecticut. Unless judicial appeals delay the project, CL&P expects to begin construction on portions of the project in 2003. This project is exempt from the State of Connecticut's imposed moratorium on the approval of new electric and natural gas transmission projects. At June 30, 2003, CL&P has capitalized approximately $10.6 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, and CL&P will own 80 percent, or approximately $400 million, of the project. This project is also exempt from the State of Connecticut's imposed moratorium on the approval of new electric and natural gas transmission projects. At June 30, 2003, CL&P has capitalized approximately $4.9 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, changing pricing and operational rules in the New England and New York energy markets and pending business issues between the parties, the expected in-service date is currently under evaluation. This project is also exempt from the State of Connecticut's imposed moratorium on the approval of new electric and natural gas transmission projects. At June 30, 2003, CL&P has capitalized approximately $5.4 million related to this project. 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, and a final decision is expected in the third quarter of 2003. If approved, construction of the facility, which is expected to cost approximately $60 million, could begin in late 2003 or in early 2004. This project is also exempt from the State of Connecticut's imposed moratorium on the approval of new electric and natural gas transmission projects. At June 30, 2003, Yankee Gas has capitalized approximately $1.1 million related to this project. On May 23, 2003, the New Hampshire Public Utilities Commission (NHPUC) approved PSNH's acquisition of 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 is expected to close in December 2003. The purchase price will be the book value of CVEC's assets, currently estimated at approximately $9 million, and an additional $21 million to terminate a high-cost purchase power contract CVEC has with Central Vermont Public Service, its parent company. The $21 million payment will be recovered over the next several years from PSNH's customers as a Part 3 stranded cost. Utility Group Restructuring and Rate Matters -------------------------------------------- Connecticut - CL&P: Public Act No. 03-135 and Rate Proceedings Rate Case: On June 25, 2003, the Governor of Connecticut signed the Act into law. The Act amended Connecticut's 1998 electric utility industry legislation. Among key features, the Act created a Transitional Standard Offer (TSO) period from 2004 through 2006 that allows the base rate cap for customers to return to 1996 levels, an increase of up to 11.1 percent. If energy supply costs exceed levels established in the TSO rate, they will be recovered through an energy adjustment clause or through the FMCC charge in the case of incremental LMP costs. Neither the energy adjustment clause nor the FMCC charge are subject to the base rate cap. Accordingly, the ultimate rate increase for customers could exceed 11.1 percent. The Act also requires that the utilities be allowed to recover from customers who do not choose an alternative supplier their full cost of procuring power and allows those utilities to earn at least a 0.50 mill fee on power purchases during the TSO period. That fee can increase to 0.75 mills if the utility beats certain regional benchmarks. One mill is equal to one-tenth of a cent. All procurement compensation is excluded from review of a utility's rates and earnings sharing mechanism calculations. On July 1, 2003, CL&P made a filing with the DPUC to establish TSO service and to set the TSO rates equal to December 31, 1996 total rate levels. Under the Act, the DPUC must establish the TSO rates no later than December 15, 2003, with an effective date for the TSO rates of January 1, 2004. Under the plan, CL&P expects to acquire competitively priced supply this fall for TSO beyond December 31, 2003, when its current standard offer supplier contracts expire. The Act also required CL&P to file a four-year transmission and distribution plan with the DPUC. Accordingly, on August 1, 2003, CL&P filed a rate case that amended rate schedules and proposed changes in electric distribution service and transmission service rates to reflect a four-year plan for the provision of such services. The amended rate schedules were designed to increase CL&P's annual distribution component of revenues by the following approximate amounts, beginning January 1, 2004, through January 1, 2007: ------------------------------------------------------------------------------- Incremental Percentage Incremental Increase/(Decrease) in Year Increase/(Decrease) Total TSO Rates ------------------------------------------------------------------------------- 2004 $133.5 million 6.0% 2005 23.2 million 1.0% 2006 24.0 million 1.0% 2007 24.1 million 1.0% ------------------------------------------------------------------------------- In its rate case, CL&P cited the need for rate increases to recover 1) increased costs of providing service, including higher pension and health care costs, 2) an approximately $250 million per year distribution capital program, and 3) the recruitment and training of new workers as a result of the aging of the current skilled electric craft worker population. CL&P also requested a tracking mechanism that could annually adjust the electric transmission rates to reflect FERC-approved transmission tariffs. However, if the transmission rate tracking mechanism filing process does not prove to be acceptable to the DPUC, CL&P proposed amended annual rate schedules in its rate application that will be designed to adjust CL&P's rates for transmission costs during the rate period. Seabrook Disposition of Proceeds: CL&P sold its share of the Seabrook nuclear unit on November 1, 2002. CL&P received $37 million and recorded a gain on the sale of approximately $16 million. The gain was recorded as a regulatory liability and, when offset by the decommissioning top off and other adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale. This filing described CL&P's treatment of its share of the proceeds from the sale of the Seabrook nuclear unit. Hearings in this docket are scheduled for the third quarter of 2003 with a final decision scheduled to be issued in December 2003. Energy Conservation Program: As a result of difficulty balancing the 2003 through 2005 state budget, the State of Connecticut has proposed redirecting funds collected through a 3 mill energy conservation adder on retail electric bills to the state's general fund. If approved as part of a final state budget, the change could reduce CL&P net income, as CL&P is currently allowed to earn an incentive on its energy conservation programs. In 2002, that incentive added approximately $3.3 million to CL&P's net income. In mid- 2003, in anticipation of a reduction in those programs, CL&P reduced its workforce by approximately 60 employees involved in delivering energy conservation programs to customers. CL&P is working with state officials and other parties to find ways to restore, at least partially, the funding for these programs. One way under consideration would be to use securitization to generate approximately two- thirds of such funding for two years, which would also permit the continued opportunity for CL&P to earn incentives. Earnings Sharing: CL&P continues to be subject to the earnings sharing mechanism implemented by the DPUC, under which CL&P's net income in excess of a 10.3 percent return on equity is shared equally by shareholders and ratepayers. For the twelve-month period ended June 30, 2003, CL&P earned in excess of a 10.3 percent return on equity and recorded an associated regulatory liability. CL&P expects to make its earnings sharing filing with the DPUC in August 2003. Competitive Transition Assessment and System Benefits Charge (SBC) Reconciliation: On April 3, 2003, CL&P filed its annual CTA and 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. This amount has been recorded as a regulatory liability. CL&P has proposed that a portion of the CTA/GSC overrecovery be utilized to reduce the nuclear stranded cost regulatory asset and that the remaining amount be carried forward through 2003. For the same period, SBC revenues exceeded the SBC revenue requirement by approximately $22.4 million. In compliance with a prior decision of the DPUC, a portion of the SBC overrecovery was applied to regulatory assets, and the remaining overrecovery of $18.6 million was applied to the CTA. Management expects a decision from the DPUC in this docket by the end of 2003. Connecticut - Yankee Gas: Infrastructure Expansion Rate Mechanism (IERM): On June 25, 2003, the DPUC issued a final decision in the 2002 IERM docket. The DPUC concluded that the basic concept of IERM is valid, appropriate and beneficial. The decision approved 10 of the 22 proposed IERM projects and encouraged Yankee Gas to seek recovery of the costs of these projects in its next rate case. The DPUC ordered Yankee Gas to provide a credit to customers for 2002 and 2003 overrecoveries estimated at $3.6 million during December 2003 through February 2004. This amount has been recorded as a regulatory liability. New Hampshire: Transition Service: On February 1, 2003, in accordance with the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement) and state law, PSNH raised the transition service rate for commercial, industrial, and residential customers. These rates are not fully recovering its generation and purchased-power costs, including earning a return on PSNH's generation investment. Transition service underrecoveries, in addition to other stranded cost components of the Stranded Cost Recovery Charge (SCRC), amounted to approximately $29 million. This amount excludes the gain on the sale of Seabrook. Delivery Rate Case: PSNH's delivery rates are fixed by the Restructuring Settlement until February 1, 2004. Under the Restructuring Settlement, PSNH is required to file a rate case by December 31, 2003 to determine PSNH's delivery rates. SCRC Reconciliation Filing: On May 1, 2003, PSNH filed a SCRC reconciliation filing for the period January 1, 2002, through December 31, 2002 with the NHPUC. Hearings in this docket are scheduled for October 2003 with an order expected by the end of 2003. Management does not expect the outcome of this docket to have a material adverse impact on PSNH's net income or its financial position. Renegotiation of Power Purchase Obligations: 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. On May 22, 2003, the NHPUC issued 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. On May 30, 2003, under the terms of this settlement, PSNH made lump sum payments totaling $20.4 million to the fourteen IPPs, in exchange for the termination of the existing long-term power purchase obligations between PSNH and these IPPs effective on May 31, 2003. PSNH continues to have an obligation under state and federal law to purchase the output from these fourteen IPPs. However, these purchases will be made at lower prices. The buy out payments have been recorded as regulatory assets, and will be recovered, including a return, over the remaining term of the initial contractual arrangements as Part 2 stranded costs. The estimated savings of the negotiated buyout is approximately $5 million, of which PSNH is entitled to retain 20 percent. PSNH's 20 percent of the savings amount will be recognized as income over the remaining terms of the contracts. Massachusetts: Transition Cost Reconciliation: On March 31, 2003, WMECO filed its 2002 annual transition cost reconciliation with the DTE. This filing reconciled the recovery of generation-related stranded 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. Management does not expect the outcome of this docket to have a material adverse impact on WMECO's net income or its financial position. Default Service: On May 21, 2003, the DTE approved WMECO's default service price of $0.068 per kilowatt-hour (kWh) for the period July 1, 2003, through December 31, 2003. For the period of January 1, 2003, through June 30, 2003, WMECO's default service price was $0.051 per kWh. For information regarding commitments and contingencies related to restructuring and rate matters, see Note 4A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements. Critical Accounting Policies and Estimates Update ------------------------------------------------- Pension Plan Accounting: 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 June 30, 2003, the estimated fair value of Plan assets exceeded the December 31, 2002 ABO by approximately $170 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 pension liability. Energy Trading and Derivative Accounting: In April 2003, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amended existing derivative accounting guidance. SFAS No. 149 incorporates interpretations that were included in previous Derivative Implementation Group (DIG) guidance, clarifies certain conditions, and amends other existing pronouncements. It is effective for contracts entered into or modified after June 30, 2003. The new rules indicate that derivative contracts that are subject to unplanned netting and can be settled for cash versus delivery would no longer qualify for the normal purchases and sales exception, which would require fair value accounting. Management is evaluating the impacts of SFAS No. 149, particularly the definition of "subject to unplanned netting." This could impact Select Energy's wholesale marketing contracts that currently qualify for the normal purchases and sales exception. Since most supply contracts can be settled for cash, and most delivery contracts cannot, this could result in asymmetrical accounting. There are three potential outcomes for the implementation of the guidance in SFAS No. 149. There could be no change in NU's accounting, and accrual accounting would continue with earnings recorded as energy is delivered. A second outcome could result in Select Energy's supply contracts being recorded at fair value and being treated as cash flow hedges. Under this outcome, the fair value of the contracts would be recorded as derivative assets or liabilities with offsets recorded to accumulated other comprehensive income, which is a component of equity. The third outcome could be that Select Energy's supply contracts would be recorded at fair value with changes in fair value impacting net income, but delivery contracts would likely remain on accrual accounting. On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning of "not clearly and closely related regarding contracts with a price adjustment feature" as it relates to the election of the normal purchase and sales exception to derivative accounting. The implementation of this guidance is required for the fourth quarter of 2003 for NU. Management is currently evaluating the impacts of Issue No. C-20. When implemented, DIG Issue No. C-20 may result in CL&P recording the fair value of two existing contracts as derivative liabilities with offsetting regulatory assets, as these contracts are part of stranded costs, and management believes that these costs will continue to be recoverable in rates. 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. Website: Additional financial information is available through NU's website at www.nu.com. RESULTS OF OPERATIONS - NU CONSOLIDATED The components of significant income statement variances for the second quarter of 2003 and the first six months of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ----------------------------------- Second Six Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $316 28% $719 30% Operating Expenses: Fuel, purchased and net interchange power 267 43 609 45 Other operation 32 16 24 6 Maintenance (5) (7) (12) (9) Depreciation (3) (5) (6) (5) Amortization 16 (a) 53 (a) Amortization of rate reduction bonds 1 2 (6) (8) Taxes other than income taxes (3) (6) (4) (3) ---- --- ---- --- Total operating expenses 305 29 658 30 ---- --- ---- --- Operating income 11 12 61 29 ---- --- ---- --- Interest expense, net (10) (14) (13) (9) Other income/(loss), net (1) (54) 14 (a) ---- --- ---- --- Income before income tax expense 20 74 88 (a) Income tax expense 22 (a) 48 (a) Preferred dividends of subsidiaries - - - - ---- --- ---- --- Net income $ (2) (7)% $ 40 83% ==== === ==== === (a) Percent greater than 100. Comparison of the Second Quarter of 2003 to the Second Quarter of 2002 Operating Revenues Total revenues increased $316 million or 28 percent in the second quarter of 2003, compared with the same period in 2002, due to higher revenues from NU Enterprises ($284 million after intercompany eliminations) and higher Utility Group revenues ($32 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 and higher short-term sales. The Utility Group revenue increase is primarily due to higher retail revenue ($70 million), partially offset by lower wholesale revenue ($37 million). The regulated retail revenue increase is primarily due to CL&P's recovery of incremental LMP costs ($30 million), higher Yankee revenue resulting from higher purchased gas adjustment clause revenues ($18 million), increased sales volumes ($4 million) and higher price mix among customer classes ($11 million) for the regulated companies. Regulated retail electric kWh sales increased by 0.6 percent and firm natural gas sales increased by 4.1 percent in the second quarter of 2003. The regulated wholesale revenue decrease is primarily due to lower PSNH sales as a result of owning less generation due to the sale of Seabrook. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $267 million or 43 percent in the second quarter of 2003, primarily due to higher wholesale energy purchases at NU Enterprises ($293 million after intercompany eliminations), partially offset by lower purchased-power costs for the Utility Group ($22 million after intercompany eliminations). Other Operation Other operation expense increased $32 million primarily due to higher competitive business expenses resulting from business growth ($20 million), higher RMR related transmission expense ($15 million), and higher regulated business administrative and general expenses resulting from higher health care costs and lower pension income ($8 million), partially offset by lower nuclear expense resulting from the sale of Seabrook ($11 million). Maintenance Maintenance expense decreased $5 million primarily due to lower nuclear expense resulting from the sale of Seabrook ($14 million), partially offset by higher fossil production expenses resulting from maintenance overhauls ($5 million) and higher electric distribution and transmission expense ($3 million). Depreciation Depreciation decreased $3 million in 2003 primarily due to lower decommissioning and depreciation expenses, resulting from the sale of Seabrook in the last quarter of 2002 ($3 million). Amortization Amortization increased $16 million in 2003, primarily due to higher amortization related to the Utility Group's recovery of stranded costs ($18 million), partially offset by the decrease in amortization of C&LM incentives ($1 million). Interest Expense, Net Interest expense, net decreased $10 million primarily due to lower interest at NU parent as a result of the interest rate swap related to its $263 million fixed-rate senior notes ($7 million), lower CL&P interest resulting from lower rates ($2 million) and lower North Atlantic Energy Corporation (NAEC) interest due to the retirement of debt ($1 million), partially offset by higher competitive businesses interest as a result of higher debt levels ($1 million). Income Tax Expense Income tax expense increased $22 million due to higher taxable income and the recording in 2002 of WMECO investment tax credits resulting from a regulatory decision ($13 million). Comparison of the First Six Months of 2003 to the First Six Months of 2002 Operating Revenues Total revenues increased $719 million or 30 percent in the first six months of 2003, compared with the same period in 2002, due to higher revenues from NU Enterprises ($515 million after intercompany eliminations) and higher Utility Group revenues ($205 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 and higher short-term sales. The Utility Group revenue increase is primarily due to higher retail revenue ($189 million) and higher wholesale revenue ($17 million). The regulated retail revenue increase is primarily due to higher retail electric sales volumes ($79 million), higher CL&P recovery of incremental LMP costs ($30 million), higher Yankee revenue resulting from higher purchased gas adjustment clause revenue ($44 million) and higher sales volumes ($29 million), and higher price mix among customer classes for the regulated companies ($5 million). Regulated retail electric kWh sales increased by 4.9 percent and firm natural gas sales increased by 13.6 percent in 2003. The regulated wholesale revenue increase is primarily due to higher prices in 2003, partially offset by lower PSNH 2003 sales as a result of less owned generation since the sale of Seabrook. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $609 million or 45 percent in 2003, primarily due to higher wholesale energy purchases at NU Enterprises ($550 million after intercompany eliminations) and higher purchased-power costs for the Utility Group ($67 million after intercompany eliminations), primarily due to Yankee Gas' higher sales and higher gas prices ($59 million). Other Operation Other operation expense increased $24 million primarily due to higher RMR related transmission expense ($14 million), higher regulated business administrative and general expenses resulting from higher health care costs and lower pension income ($15 million), and higher competitive business expenses resulting from business growth ($6 million), partially offset by lower nuclear expense resulting from the sale of Seabrook ($20 million). Maintenance Maintenance expense decreased $12 million primarily due to lower nuclear expense resulting from the sale of Seabrook ($22 million) partially offset by hydroelectric and fossil production expenses resulting from maintenance overhauls ($5 million) and higher electric distribution and transmission expenses ($6 million). Depreciation Depreciation decreased $6 million in 2003 primarily due to lower decommissioning and depreciation expenses resulting from the sale of Seabrook in the last quarter of 2002 ($5 million), lower NU Enterprises' depreciation resulting from a study which resulted in lengthening the useful lives of certain generation assets ($3 million), partially offset by higher Utility Group depreciation resulting from higher plant balances. Amortization Amortization increased $53 million 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. Interest Expense, Net Interest expense, net decreased $13 million primarily due to lower interest at NU parent as a result of the interest rate swap related to its $263 million fixed-rate senior notes ($5 million), lower interest for the regulated subsidiaries resulting from lower rates ($6.5 million) and lower NAEC interest due to the retirement of debt ($2 million), partially offset by higher competitive businesses interest as a result of higher debt levels ($1 million). Other Income/(Loss), Net Other income/(loss), net increased $14 million primarily due to a charge in the first quarter of 2002 reflecting a write-down of NU's investments in NEON and Acumetrics ($15 million). Income Tax Expense Income tax expense increased $48 million due to higher taxable income and the recording in 2002 of WMECO investment tax credits resulting from a regulatory decision ($13 million). 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 June 30, 2003, and the related condensed consolidated statements of income for the three-month and six-month periods ended June 30, 2003 and 2002, and of cash flows for the six-month periods ended June 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our reviews 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 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 reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim 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 sheets and consolidated statements of capitalization of Northeast Utilities and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, shareholders' equity, cash flows, and income taxes for the years 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 August 8, 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, the First Quarter 2003 Form 10-Q, 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 May 14, 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 June 30, 2003, the results of operations for the three-month and six-month periods ended June 30, 2003 and 2002, and statements of cash flows for the six- month periods ended June 30, 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 six-month periods ended June 30, 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. Reclassifications were made to regulatory asset and liability amounts and special deposits on the accompanying consolidated balance sheets. Reclassifications have also been made to the accompanying consolidated statements of cash flows. B. Regulatory Accounting and Assets The accounting policies of NU's Utility Group conform 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: --------------------------------------------------------------------- June 30, December 31, (Millions of Dollars) 2003 2002 --------------------------------------------------------------------- Recoverable nuclear costs $ 136.3 $ 85.4 Securitized regulatory assets 1,808.7 1,891.8 Income taxes, net 278.9 331.9 Unrecovered contractual obligations 231.5 239.3 Recoverable energy costs, net 309.0 299.6 Other 228.9 228.1 --------------------------------------------------------------------- Totals $2,993.3 $3,076.1 --------------------------------------------------------------------- Additionally, the Utility Group maintained $396 million and $136.5 million of regulatory liabilities at June 30, 2003 and December 31, 2002, respectively, primarily associated with CL&P's Competitive Transition Assessment, Generation Services Charge and System Benefits Charge and PSNH's Stranded Cost Recovery Charge (SCRC). These amounts are included in deferred credits and other liabilities - other on the accompanying consolidated balance sheets. 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. 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 decided to transition to net reporting effective July 1, 2002, before this consensus was reached by the EITF. The three-month and six-month periods ended June 30, 2002, reflect net reporting. The effects of this reporting for the three-month and six-month periods ended June 30, 2002, which have been previously reported, are as follows: --------------------------------------------------------------------- Operating Fuel, Purchased and (Millions of Dollars) Revenues Net Interchange Power --------------------------------------------------------------------- Three Months Ended June 30, 2002: --------------------------------------------------------------------- Operating Revenues: As previously reported $1,673.2 $1,158.4 --------------------------------------------------------------------- Impact of reclassification (531.3) (531.3) --------------------------------------------------------------------- As currently reported $1,141.9 $ 627.1 --------------------------------------------------------------------- Six Months Ended June 30, 2002: --------------------------------------------------------------------- Operating Revenues: As previously reported $3,583.9 $2,511.2 Impact of reclassification (1,157.5) (1,157.5) --------------------------------------------------------------------- As currently reported $2,426.4 $1,353.7 --------------------------------------------------------------------- In July 2003, the EITF reached a consensus on Issue No. 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, "Accounting for Derivative Instruments and Hedging Activities," and Not "Held for Trading Purposes" as Defined in EITF Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities"." The EITF did not change any existing accounting guidance and did not introduce new guidance addressing this issue. Derivative Accounting: Effective January 1, 2001, NU adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," 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 previous Derivative Implementation Group (DIG) guidance, clarifies certain conditions, and amends other existing pronouncements. It is effective for contracts entered into or modified after June 30, 2003. The new rules indicate that derivative contracts that are subject to unplanned netting and can be settled for cash versus delivery would no longer qualify for the normal purchases and sales exception, which would require fair value accounting. Management is evaluating the impacts of SFAS No. 149, particularly the definition of "subject to unplanned netting." This could impact Select Energy's wholesale marketing contracts that currently qualify for the normal purchases and sales exception. On June 25, 2003 the DIG cleared Issue No. C-20 "Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature." Management is evaluating the impact of DIG Issue No. C-20 on the consolidated financial statements, but does not believe that there will be a significant impact as a result of this issue. DIG Issue No. C-20 is effective for NU on October 1, 2003. Liabilities and Equity: In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes standards on how to classify and measure certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective for NU for the third quarter of 2003. As NU no longer has any preferred stock subject to mandatory redemption outstanding, management currently does not expect the adoption of SFAS No. 150 to have an impact on NU's consolidated financial statements. 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 tables illustrate 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 and NU's Employee Stock Purchase Plan: --------------------------------------------------------------------- For the Three Months Ended (Millions of Dollars, June 30, June 30, except per share amounts) 2003 2002 --------------------------------------------------------------------- Net income, as reported $26.9 $28.9 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 $26.3 $27.8 --------------------------------------------------------------------- Earnings per share: Basic and fully diluted - as reported $ 0.21 $ 0.22 Basic and fully diluted - pro forma $ 0.21 $ 0.21 --------------------------------------------------------------------- --------------------------------------------------------------------- For the Six Months Ended --------------------------------------------------------------------- (Millions of Dollars, June 30, June 30, except per share amounts) 2003 2002 --------------------------------------------------------------------- Net income, as reported $87.1 $47.5 Total stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effects (1.2) (2.2) --------------------------------------------------------------------- Pro forma net income $85.9 $45.3 --------------------------------------------------------------------- Earnings per share: Basic and fully diluted - as reported $ 0.69 $ 0.37 Basic and fully diluted - pro forma $ 0.68 $ 0.35 --------------------------------------------------------------------- During the six-month period ended June 30, 2003, NU granted approximately 384,000 shares of restricted stock under the Incentive Plan. The shares granted had a value of $5.4 million when granted. This amount was recorded to shareholders' equity. For the six months ended June 30, 2003, approximately $0.8 million was expensed related to the restricted stock. During the six-month period ended June 30, 2003, 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 Six Months Ended --------------------------------------------------------------------- June 30, June 30, (Millions of Dollars) 2003 2002 --------------------------------------------------------------------- Investment write-downs $ - $(17.1) Investment income 7.9 10.4 Other, net (6.6) (5.6) --------------------------------------------------------------------- Totals $ 1.3 $(12.3) --------------------------------------------------------------------- F. Sale of Customer Receivables CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. At June 30, 2003, CL&P had sold accounts receivable of $50 million to the financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. Additionally, at June 30, 2003, $4.8 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 June 30, 2003, amounts sold to CRC from CL&P but not sold to the financial institution totaling $146.5 million are included in investments in securitizable assets on the accompanying consolidated balance sheets. At December 31, 2002, $40 million of accounts receivable were sold to the financial institution. On July 9, 2003, CL&P renewed this arrangement for one year. G. 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," which requires disclosures 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. 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 by NU Enterprises. At June 30, 2003, the maximum level of exposure under guarantees by NU, primarily on behalf of NU Enterprises, totaled $421.8 million. The majority of the guarantees to NU Enterprises are for Select Energy. Additionally, NU had $10.2 million of letters of credit issued for the benefit of NU Enterprises outstanding at June 30, 2003. In conjunction with its investment in R.M. Services, Inc., NU guarantees a $3 million line of credit through 2005, of which $0.5 million was outstanding at June 30, 2003 and is included in the $421.8 million. Additionally, CL&P has obtained surety bonds in the amount of $31.1 million related to the March 2003 and April 2003 incremental locational marginal pricing (LMP) costs to comply with the DPUC's order. At June 30, 2003, NU guaranteed $42.8 million of surety bonds for NU subsidiaries, including the LMP-related surety bonds. The $42.8 million is included in NU's total guarantees of $421.8 million. These surety bonds contain ratings triggers that would require NU to post additional collateral in the event that NU's ratings are downgraded. NU currently has authorization from the Securities and Exchange Commission (SEC) to provide up to $500 million of guarantees for NU Enterprises through September 30, 2003, and has applied for authority to increase this amount to $750 million through September 30, 2005. NU has also applied to the SEC for authority to extend the $500 million limit to June 30, 2004 in the event the SEC does not act on the $750 million request by September 30, 2003. The aforementioned surety bonds are subject to a separate $50 million SEC limitation apart from the $500 million guarantee limit. The amount of guarantees outstanding for compliance with the SEC limit is approximately $283 million, which is calculated using different criteria than the maximum level of exposure of $421.8 million required to be disclosed under FIN 45. The $42.8 million of surety bonds is the same for SEC and FIN 45 purposes. 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 net income. 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 net income. 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, a component of equity, 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 net income. 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 six months of 2003, a negative $9 million, net of tax, was reclassified from other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized in net income. The related hedged transaction was also recognized in net income. A negative $0.3 million, net of tax, was recognized in net income for those derivatives that were determined to be ineffective and for the ineffective portion of cash flow hedges. Also during the second quarter of 2003, new cash flow hedge transactions were entered into that 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 $13.9 million, net of tax. Accumulated other comprehensive income at June 30, 2003, was a positive $1.6 million, net of tax (increase to equity), relating to hedged transactions, and it is estimated that $0.4 million of this balance, net of tax, will be reclassified as an increase to net income 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 June 30, 2003 and December 31, 2002. These amounts do not include premiums paid, which are recorded as prepayments and amounted to $24.8 million and $26.7 million at June 30, 2003 and December 31, 2002, respectively. These amounts also do not include premiums received, which are recorded as other current liabilities and amounted to $20.3 million and $33.9 million at June 30, 2003 and December 31, 2002, respectively. The premium amounts relate primarily to energy trading activities. --------------------------------------------------------------------- At June 30, 2003 --------------------------------------------------------------------- (Millions of Dollars) Assets Liabilities Total --------------------------------------------------------------------- Select Energy: Trading $141.0 $ (96.0) $45.0 Nontrading 2.9 (0.5) 2.4 Hedging 14.8 (10.8) 4.0 --------------------------------------------------------------------- Yankee Gas: Hedging 3.6 - 3.6 --------------------------------------------------------------------- NU Parent: Hedging 12.0 - 12.0 --------------------------------------------------------------------- Total $174.3 $(107.3) $67.0 --------------------------------------------------------------------- --------------------------------------------------------------------- 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 June 30, 2003 and December 31, 2002 were assets of $45 million and $41 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; bilateral contracts for the purchase or sale of electricity or natural gas, the fair value of which is determined using available information from external sources; and an option component of a bilateral energy purchase contract, the fair value of which is determined with the Blacks option pricing model. Select Energy's trading portfolio also includes transmission congestion contracts. The fair value of certain transmission congestion contracts is based on published market data. 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, which total $9.1 million, 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. 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 June 30, 2003 and December 31, 2002 were assets of $2.4 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 accumulated other comprehensive income. Hedges impact net income 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 2005. Select Energy has hedged its gas supply component of the risk under these agreements through NYMEX futures contracts. Under these contracts, which also extend through 2005, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements. At June 30, 2003, the NYMEX futures contracts had notional values of $26.7 million and were recorded at fair value as a derivative asset of $3.4 million, net of tax. 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 an unaffiliated customer is effectively fixed over the term of the gas service agreement with that customer for a period of time not extending beyond 2005. At June 30, 2003, the commodity swap agreement had a notional value of $8.2 million and was recorded at fair value as a derivative asset of $3.6 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 balance sheet but are equal and offsetting in the consolidated statements of income. The change in the fair value of the hedged debt of $12 million 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. On April 28, 2003, NU parent entered into a derivative to effectively lock the United States Treasury component of the interest rate on $125 million of its $150 million five-year fixed rate notes that were issued on June 3, 2003. As interest rates have declined since the notes were priced and the hedge was terminated on May 29, 2003, NU parent paid $3.9 million to the counterparties and included a loss of $3.9 million in accumulated other comprehensive income. The $3.9 million will be amortized to interest expense over the five-year term of the notes. 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 net income, 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 June 30, 2003, Select Energy calculated the market price resulting from a 10 percent change in forward market prices. That 10 percent change would result in approximately a $1.2 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 and generation assets, assuming a 10 percent change in forward market prices. At June 30, 2003, a 10 percent change in market price would have resulted in an increase or decrease in fair value of approximately $7.1 million. The impact of a change in electricity, natural gas and oil prices on Select Energy's retail and wholesale marketing portfolio at June 30, 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 in accordance with written policies and procedures by maintaining a mix of fixed and variable rate debt. At June 30, 2003, approximately 80 percent (69 percent including the debt subject to the fixed to floating interest rate swap in variable rate debt), of NU's long-term debt, including 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, including the rate on debt subject to the fixed to floating interest rate swap, annual interest expense would have increased by $7.6 million. At June 30, 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. At June 30, 2003, Select Energy maintained collateral balances from counterparties of $39.6 million. This amount is included in special deposits and other current liabilities on the accompanying consolidated balance sheets. 3. GOODWILL AND OTHER INTANGIBLE ASSETS Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other Intangible Assets," which ended the 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 six-month periods ended June 30, 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 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), while the services reporting unit is comprised of the operations of Select Energy Services, Inc. (SESI), Northeast Generation Services Company (NGS) and Woods Network Services, Inc. (Woods Network). As a result, NU's 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 June 30, 2003, NU maintained $321 million of goodwill that is no longer being amortized, $16.3 million of identifiable intangible assets and $6.8 million of intangible assets not subject to amortization, totaling $344.1 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 June 30, 2003 and December 31, 2002, by reportable segment and reporting unit is as follows: -------------------------------------------------------------------------- (Millions of Dollars) June 30, 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 June 30, 2003 and December 31, 2002, NU's intangible assets and related accumulated amortization consisted of the following: -------------------------------------------------------------------------- At June 30, 2003 -------------------------------------------------------------------------- Gross Accumulated Net (Millions of Dollars) Balance Amortization Balance -------------------------------------------------------------------------- Intangible assets subject to amortization: Exclusivity agreement $17.7 $5.9 $11.8 Customer list 6.6 2.2 4.4 Customer backlog and employment related agreements 0.1 - 0.1 -------------------------------------------------------------------------- Totals $24.4 $8.1 $16.3 -------------------------------------------------------------------------- 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 $1.8 million and $0.8 million for the six months ended June 30, 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 acquisitions and dispositions occur in the future. 4. COMMITMENTS AND CONTINGENCIES A. Utility Group Restructuring and Rate Matters (CL&P, PSNH, WMECO) Connecticut: On March 1, 2003, the New England Independent System Operator implemented standard market design (SMD). As part of SMD, LMP is utilized to assign value and causation to transmission congestion and line losses. Management believes that under the terms of its standard offer service contracts with its standard offer suppliers, the incremental costs associated with line 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. 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. CL&P incurred $62 million of incremental LMP costs from March 1, 2003 through June 30, 2003. As incurred, these costs were recorded as recoverable energy costs and are included in regulatory assets on the accompanying consolidated balance sheets. CL&P received approval for recovery of these costs through an additional charge on customer bills and began recovering them on May 1, 2003, subject to refund and on a two month lag. Approximately $30 million has been recovered through June 30, 2003. This amount is included in operating revenues and offset by amortization. If it is ultimately concluded that the incremental LMP costs are the responsibility of the standard offer service suppliers, NU Enterprises' pre-tax earnings for the six months ended June 30, 2003 would be reduced by approximately $35 million, and CL&P would eliminate the accounts payable to the standard offer service suppliers with a reduction to operating expenses. At the same time, a regulatory liability in the same amount would be recorded with a reduction to operating revenues. This amount could be material, and there would be an impact to NU's and NU Enterprises' net income, but there would be no impact on CL&P's net income. New Hampshire: On May 1, 2003, PSNH filed a SCRC reconciliation filing for the period January 1, 2002, through December 31, 2002 with the New Hampshire Public Utilities Commission. Hearings in this docket are scheduled for October 2003 with an order expected by the end of 2003. Management does not expect the outcome of this docket to have a material adverse impact on PSNH's net income 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 generation-related stranded 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. Management does not expect the outcome of this docket to have a material adverse impact on WMECO's net income or its financial position. B. NRG Energy, Inc. Exposures (CL&P, Yankee Gas, NGS) Certain subsidiaries of NU, including CL&P, Yankee Gas and NGS, have entered into various transactions with subsidiaries of NRG Energy, Inc. (NRG). On May 14, 2003, NRG filed a voluntary bankruptcy petition. NRG-related exposures to NU as a result of these transactions relate to 1) the recovery of CL&P's station service billings from NRG, 2) NRG's standard offer service contract with CL&P, 3) the recovery of congestion charges incurred by NRG prior to the implementation of SMD on March 1, 2003, and 4) the recovery of Yankee Gas' and NGS' capital expenditures that were incurred related to NRG's generating plant that is now abandoned. While it is unable to determine the ultimate outcome of these issues, 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. C. 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 $5.4 billion at June 30, 2003 as follows (millions of dollars): --------------------------------------------------------------------- Year --------------------------------------------------------------------- 2003 $2,667.8 2004 1,657.0 2005 594.3 2006 260.0 2007 221.4 --------------------------------------------------------------------- Total $5,400.5 --------------------------------------------------------------------- Select Energy's purchase contract amounts can exceed the amount expected to be reported in fuel, purchased and net interchange power as energy trading purchases are classified net with the corresponding revenues. 5. COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO) Total comprehensive income, which includes all comprehensive income items, is as follows: -------------------------------------------------------------------------- Six Months Ended June 30, -------------------------------------------------------------------------- (Millions of Dollars) 2003 2002 -------------------------------------------------------------------------- NU consolidated $73.9 $81.4 CL&P 30.1 30.4 PSNH 21.9 26.5 WMECO 8.7 22.2 -------------------------------------------------------------------------- Accumulated other comprehensive income fair value adjustments of NU's qualified cash flow hedging instruments are as follows: -------------------------------------------------------------------------- June 30, December 31, (Millions of Dollars, Net of Tax) 2003 2002 -------------------------------------------------------------------------- Balance at beginning of period $15.5 $(36.9) -------------------------------------------------------------------------- Hedged transactions recognized into net income (9.0) 17.0 Change in fair value 2.3 29.2 Cash flow transactions entered into for the period (7.2) 6.2 -------------------------------------------------------------------------- Net change associated with the current period hedging transactions (13.9) 52.4 -------------------------------------------------------------------------- Total fair value adjustments included in accumulated other comprehensive income $ 1.6 $ 15.5 -------------------------------------------------------------------------- Accumulated other comprehensive income items unrelated to NU's qualified cash flow hedging instruments totaled $0.2 million in gains and $0.6 million in losses at June 30, 2003 and December 31, 2002, respectively. These amounts relate to unrealized gains and 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, Six Months Ended June 30, except share information) 2003 2002 -------------------------------------------------------------------------- Income before preferred dividends of subsidiaries $89.9 $50.3 Preferred dividends of subsidiaries 2.8 2.8 -------------------------------------------------------------------------- Net income $87.1 $47.5 -------------------------------------------------------------------------- Basic EPS common shares outstanding (average) 126,880,397 129,590,899 Dilutive effect of employee stock options 102,506 280,596 -------------------------------------------------------------------------- Fully diluted EPS common shares outstanding (average) 126,982,903 129,871,495 -------------------------------------------------------------------------- Basic and fully diluted EPS $0.69 $0.37 -------------------------------------------------------------------------- 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 70 percent and 83 percent of NU's total revenues for the six months ended June 30, 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. The NU Enterprises segment includes Select Energy, NGC, SESI, NGS, and their respective subsidiaries. HWP and Woods Network are also included in the NU Enterprises segment. On January 1, 2000, Select Energy began serving one half of CL&P's standard offer load for a four-year period ending on 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 $349 million or 26 percent for the six months ended June 30, 2003 and approximately $304 million or 42 percent for the six months ended June 30, 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 $213.7 million or 16 percent of total NU Enterprises' revenues for the six months ended June 30, 2003. Additionally, WMECO's purchases from Select Energy represented approximately $68.2 million and $1.3 million of total NU Enterprises' revenues for the six months ended June 30, 2003 and 2002, respectively. No other individual customer represented in excess of 10 percent of NU Enterprises' revenues for the six months ended June 30, 2003 or 2002. 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 Energy System, Inc. 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 June 30, 2003 --------------------------------------------------------------------------- Utility Group Eliminations (Millions of ------------- NU and Dollars) Electric Gas Enterprises Other Total --------------------------------------------------------------------------- Operating revenues $923.8 $ 72.2 $665.7 $(204.2) $1,457.5 Depreciation and amortization (95.8) (5.8) (5.3) (0.6) (107.5) Other operating expenses (752.3) (66.9) (629.6) 203.9 (1,244.9) --------------------------------------------------------------------------- Operating income/(loss) 75.7 (0.5) 30.8 (0.9) 105.1 Interest expense, net (42.9) (3.4) (12.0) (1.2) (59.5) Other (loss)/ income, net (0.1) (0.5) 2.4 (1.0) 0.8 Income tax (expense)/ benefit (12.7) 1.5 (9.3) 2.4 (18.1) Preferred dividends (1.4) - - - (1.4) --------------------------------------------------------------------------- Net income/ (loss) $ 18.6 $ (2.9) $ 11.9 $ (0.7) $ 26.9 --------------------------------------------------------------------------- --------------------------------------------------------------------------- For the Six Months Ended June 30, 2003 --------------------------------------------------------------------------- Utility Group Eliminations (Millions of ------------- NU and Dollars) Electric Gas Enterprises Other Total --------------------------------------------------------------------------- Operating revenues $1,989.2 $224.4 $1,355.5 $(423.1) $ 3,146.0 Depreciation and amortization (230.7) (11.4) (10.2) (1.2) (253.5) Other operating expenses (1,567.6) (183.0) (1,294.5) 421.7 (2,623.4) --------------------------------------------------------------------------- Operating income /(loss) 190.9 30.0 50.8 (2.6) 269.1 Interest expense, net (86.5) (6.6) (23.1) (6.8) (123.0) Other (loss)/ income, net (0.5) (1.0) 2.9 (0.1) 1.3 Income tax (expense)/ benefit (40.1) (9.4) (13.5) 5.5 (57.5) Preferred dividends (2.8) - - - (2.8) --------------------------------------------------------------------------- Net income/ (loss) $ 61.0 $ 13.0 $ 17.1 $ (4.0) $ 87.1 --------------------------------------------------------------------------- Total assets $7,534.1 $953.2 $2,013.0 $ (80.6) $10,419.7 --------------------------------------------------------------------------- Total investments in plant $ 20l.1 $ 22.8 $ 8.2 $ 4.6 $ 236.7 --------------------------------------------------------------------------- --------------------------------------------------------------------------- For the Three Months Ended June 30, 2002 --------------------------------------------------------------------------- Utility Group Eliminations (Millions of ------------- NU and Dollars) Electric Gas Enterprises Other Total --------------------------------------------------------------------------- Operating revenues $915.7 $50.6 $323.3 $(147.7) $1,141.9 Depreciation and amortization (82.3) (5.8) (5.1) (0.6) (93.8) Other operating expenses (735.7) (42.6) (322.7) 146.9 (954.1) --------------------------------------------------------------------------- Operating income/(loss) 97.7 2.2 (4.5) (1.4) 94.0 Interest expense, net (46.1) (3.6) (10.7) (8.6) (69.0) Other (loss)/ income, net (0.9) 0.4 0.3 1.9 1.7 Income tax (expense)/ benefit (5.8) 0.4 5.7 3.3 3.6 Preferred dividends (1.4) - - - (1.4) --------------------------------------------------------------------------- Net income/ (loss) $ 43.5 $(0.6) $ (9.2) $ (4.8) $ 28.9 --------------------------------------------------------------------------- --------------------------------------------------------------------------- For the Six Months Ended June 30, 2002 --------------------------------------------------------------------------- Utility Group Eliminations (Millions of ------------- NU and Dollars) Electric Gas Enterprises Other Total --------------------------------------------------------------------------- Operating revenues $1,856.3 $154.9 $724.6 $(309.4) $2,426.4 Depreciation and amortization (187.0) (12.4) (11.9) (1.1) (212.4) Other operating expenses (1,458.1) (115.2) (737.8) 305.4 (2,005.7) --------------------------------------------------------------------------- Operating income /(loss) 211.2 27.3 (25.1) (5.1) 208.3 Interest expense, net (93.9) (7.4) (21.8) (12.8) (135.9) Other income/ (loss), net 2.2 (0.1) (0.6) (13.8) (12.3) Income tax (expense)/ benefit (33.4) (7.9) 17.8 13.7 (9.8) Preferred dividends (2.8) - - - (2.8) --------------------------------------------------------------------------- Net income/ (loss) $ 83.3 $ 11.9 $(29.7) $ (18.0) $ 47.5 --------------------------------------------------------------------------- Total investments in plant $ 168.3 $ 20.6 $ 13.9 $ 9.7 $ 212.5 --------------------------------------------------------------------------- THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2003 2002 ---------------- ---------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash $ 2,609 $ 159 Investments in securitizable assets 146,532 178,908 Receivables, net 61,416 88,001 Accounts receivable from affiliated companies 69,853 51,060 Unbilled revenues 4,523 5,801 Notes receivable from affiliated companies - 1,900 Fuel, materials and supplies, at average cost 30,757 32,379 Prepayments and other 9,459 19,407 -------------- -------------- 325,149 377,615 -------------- -------------- Property, Plant and Equipment: Electric utility 3,238,499 3,139,128 Less: Accumulated depreciation 1,145,148 1,113,991 -------------- -------------- 2,093,351 2,025,137 Construction work in progress 179,850 153,556 -------------- -------------- 2,273,201 2,178,693 -------------- -------------- Deferred Debits and Other Assets: Regulatory assets 1,685,449 1,702,677 Prepaid pension 290,456 276,173 Other 113,472 96,925 -------------- -------------- 2,089,377 2,075,775 -------------- -------------- Total Assets $ 4,687,727 $ 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)
June 30, December 31, 2003 2002 ---------------- ---------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to affiliated companies $ 15,300 $ - Accounts payable 157,833 174,890 Accounts payable to affiliated companies 151,976 117,904 Accrued taxes 24,869 34,350 Accrued interest 9,922 10,077 Other 43,366 48,495 -------------- -------------- 403,266 385,716 -------------- --------------- Rate Reduction Bonds 1,186,218 1,245,728 -------------- -------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 739,196 756,461 Accumulated deferred investment tax credits 92,147 93,408 Deferred contractual obligations 221,586 234,537 Other 394,555 276,325 -------------- -------------- 1,447,484 1,360,731 -------------- -------------- Capitalization: Long-Term Debt 829,115 827,866 -------------- -------------- 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 326,825 327,299 Retained earnings 318,524 308,554 Accumulated other comprehensive loss (257) (363) -------------- -------------- Common Stockholder's Equity 705,444 695,842 -------------- -------------- Total Capitalization 1,650,759 1,639,908 -------------- -------------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization $ 4,687,727 $ 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 Six Months Ended June 30, June 30, ----------------------------- ----------------------------- 2003 2002 2003 2002 -------------- -------------- -------------- -------------- (Thousands of Dollars) Operating Revenues $ 615,268 $ 581,731 $ 1,321,184 $ 1,186,151 ------------ ------------ ------------ ------------ Operating Expenses: Operation - Fuel, purchased and net interchange power 353,211 344,497 773,416 703,197 Other 100,928 78,564 176,767 148,776 Maintenance 20,676 17,744 31,854 32,268 Depreciation 25,911 26,110 51,327 49,406 Amortization of regulatory assets, net 22,904 18,100 50,247 15,069 Amortization of rate reduction bonds 23,333 21,007 50,819 49,077 Taxes other than income taxes 30,006 30,181 79,368 78,719 ------------ ------------ ------------ ------------ Total operating expenses 576,969 536,203 1,213,798 1,076,512 ------------ ------------ ------------ ------------ Operating Income 38,299 45,528 107,386 109,639 Interest Expense: Interest on long-term debt 9,900 9,638 20,012 20,389 Interest on rate reduction bonds 17,762 19,073 35,906 38,484 Other interest 353 1,068 756 1,315 ------------ ------------ ------------ ------------ Interest expense, net 28,015 29,779 56,674 60,188 ------------ ------------ ------------ ------------ Other Income, Net 1,219 2,704 1,963 6,183 ------------ ------------ ------------ ------------ Income Before Income Tax Expense 11,503 18,453 52,675 55,634 Income Tax Expense 5,439 7,046 19,889 22,543 ------------ ------------ ------------ ------------ Net Income $ 6,064 $ 11,407 $ 32,786 $ 33,091 ============ ============ ============ ============ 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)
Six Months Ended June 30, ------------------------------ 2003 2002 ------------- ------------- (Thousands of Dollars) Operating Activities: Net income $ 32,786 $ 33,091 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation 51,327 49,406 Deferred income taxes and investment tax credits, net (22,612) (34,857) Net (deferral)/amortization of recoverable energy costs (28,779) 14,452 Amortization of regulatory assets, net 50,247 15,069 Amortization of rate reduction bonds 50,819 49,077 Prepaid pension (14,283) (26,450) Net other sources of cash 34,363 45,652 Changes in working capital: Receivables and unbilled revenues, net 9,070 (744) Fuel, materials and supplies 1,622 167 Accounts payable 17,015 (3,109) Accrued taxes (9,481) (13,971) Investments in securitizable assets 32,376 7,482 Other working capital (excludes cash) 4,727 26,543 ---------- ---------- Net cash flows provided by operating activities 209,197 161,808 ---------- ---------- Investing Activities: Investments in plant (138,512) (103,080) NU system Money Pool borrowing 17,200 105,450 Other investment activities, net (2,809) (46,599) ---------- ---------- Net cash flows used in investing activities (124,121) (44,229) ---------- ---------- Financing Activities: Repurchase of common shares - (49,996) Retirement of rate reduction bonds (59,510) (32,803) Cash dividends on preferred stock (2,779) (2,779) Cash dividends on common stock (20,037) (30,036) Other financing activities, net (300) (261) ---------- ---------- Net cash flows used in financing activities (82,626) (115,875) ---------- ---------- Net increase in cash 2,450 1,704 Cash - beginning of period 159 773 ---------- ---------- Cash - end of period $ 2,609 $ 2,477 ========== ========== The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Financial Condition and Results of Operations CL&P is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management's discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the First Quarter 2003 Form 10-Q, the NU 2002 Form 10-K, and the current report on Form 8-K dated May 14, 2003. RESULTS OF OPERATIONS The components of significant income statement variances for the second quarter of 2003 and the first six months of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ----------------------------------- Second Six Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $ 34 6% $135 11% Operating Expenses: Fuel, purchased and net interchange power 9 3 70 10 Other operation 22 28 28 19 Maintenance 3 17 (1) (1) Depreciation - - 2 4 Amortization of regulatory assets, net 5 27 35 (a) Amortization of rate reduction bonds 2 11 2 4 Taxes other than income taxes - - 1 1 ---- ---- ---- ---- Total operating expenses 41 8 137 13 ---- ---- ---- ---- Operating income (7) (16) (2) (2) ---- ---- ---- ---- Interest expense, net (2) (6) (3) (6) Other income, net (2) (55) (4) (68) Income before income tax expense (7) (38) (3) (5) Income tax expense (2) (23) (3) (12) ---- ---- ---- ---- Net income $ (5) (47)% $ - -% ==== ==== ==== ==== (a) Percent greater than 100. Comparison of the Second Quarter of 2003 to the Second Quarter of 2002 Operating Revenues Operating revenues increased $34 million or 6 percent in the second quarter of 2003, compared with the same period in 2002, primarily due to higher retail revenues resulting from the collection of incremental LMP costs beginning in May 2003 ($30 million). Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased by $9 million or 3 percent in the second quarter of 2003, compared with the same period in 2002, primarily due to costs associated with SMD. Other Operation and Maintenance Other operation and maintenance (O&M) expenses increased $25 million in the second quarter of 2003, compared with the same period in 2002, primarily due to higher reliability must run (RMR) related transmission costs ($15 million), higher distribution costs ($5 million) and higher administrative costs resulting from higher healthcare costs and lower pension income ($5 million). Amortization of Regulatory Assets, Net Amortization of regulatory assets, net expense increased $5 million primarily due to higher amortization related to the recovery of stranded costs ($15 million), partially offset by lower amortization of recoverable nuclear costs ($8 million). Interest Expense, Net Interest expense, net decreased $2 million primarily due to lower interest on rate reduction bonds. Other Income, Net Other income, net decreased $2 million primarily due to lower conservation and load management (C&LM) incentive income. Income Tax Expense Income tax expense decreased $2 million primarily due to lower book taxable income. Comparison of the First Six Months of 2003 to the First Six Months of 2002 Operating Revenues Operating revenues increased by $135 million or 11 percent in 2003, compared with the same period in 2002, primarily due to higher retail revenues ($77 million) and higher wholesale revenues ($55 million). Retail revenues were higher primarily due to the collection of incremental LMP costs beginning in May 2003 ($30 million) and higher retail sales ($48 million). Retail kilowatt-hour (kWh) sales increased by 4.4 percent in 2003, of which 2.7 percent was related to weather. Wholesale revenues were higher primarily due to higher market prices in 2003. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $70 million or 10 percent in 2003, primarily due to incremental LMP costs which were recovered from customers ($30 million) and higher standard offer purchases as a result of higher retail sales. Other Operation and Maintenance Other O&M expenses increased by $27 million primarily due to higher RMR related transmission costs ($14 million), higher administrative costs resulting from higher healthcare costs and lower pension income ($10 million) and higher transmission and distribution expenses ($12 million), partially offset by lower related nuclear expenses ($10 million) as a result of the final DPUC order regarding the CL&P Millstone use of proceeds docket in the first quarter of 2003. Depreciation Depreciation expense increased $2 million primarily due to higher utility plant balances in 2003 resulting from plant additions. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net expense increased $35 million primarily due to higher amortization related to the recovery of stranded costs ($58 million), partially offset by lower amortization of recoverable nuclear costs ($22 million). Interest Expense, Net Interest expense, net decreased $3 million primarily due to lower interest on rate reduction bonds. Other Income, Net Other income, net decreased $4 million primarily due to lower interest and dividend income ($1 million), lower C&LM incentive income ($1 million), and higher charitable donations made in 2003 ($1 million). Income Tax Expense Income tax expense decreased $3 million primarily due to lower book taxable income. LIQUIDITY At June 30, 2003, CL&P had no borrowings outstanding on the Utility Group's $300 million revolving credit line. This credit line matures on November 11, 2003 and management anticipates extending this credit line. CL&P has been put on a negative outlook by Moody's Investor Services. On July 9, 2003, CL&P renewed an agreement for one year under which it can access up to $100 million by selling certain of its accounts receivable and unbilled revenues. At June 30, 2003, CL&P had $50 million of accounts receivable and unbilled revenues sold under this arrangement. For more information regarding CL&P's accounts receivable facility, see Note 1F, "Sale of Customer Receivables," to the consolidated financial statements. Through June 30, 2003, CL&P has recovered approximately $30 million of incremental LMP costs from its customers and has withheld payment of these incremental LMP costs from its standard offer service suppliers. This has positively impacted CL&P's liquidity. In July 2003, CL&P began depositing these recoveries into an escrow account. Accordingly, further recovery of these costs will not impact CL&P's liquidity. When the issue of responsibility for incremental LMP costs is resolved, which is expected to be in early 2004, there will be a negative impact on CL&P's liquidity for the amounts recovered but not deposited into the escrow account, as these amounts are paid to standard offer service suppliers or returned to customers. CL&P's net cash flows provided by operating activities increased to $209.2 million for the six months ended June 30, 2003 from $161.8 million for the same period in 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 increases in working capital items. CL&P's net cash flows used in investing activities increased to $124.1 million for the first six months of 2003 from $44.2 million for the same period in 2002. The increase is primarily due to lower NU system Money Pool borrowings in 2003. Financing activities decreased in 2003 as a result of the repurchase of common shares in 2002. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2003 2002 ----------- ------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash $ 1,405 $ 5,319 Receivables, net 63,874 68,204 Accounts receivable from affiliated companies 998 9,667 Taxes receivable 16,812 - Unbilled revenues 33,662 32,004 Notes receivable from affiliated companies - 23,000 Fuel, materials and supplies, at average cost 45,644 49,182 Prepayments and other 24,014 10,032 ------------- ------------- 186,409 197,408 ------------- ------------- Property, Plant and Equipment: Electric utility 1,487,924 1,431,774 Other 6,180 6,195 ------------- ------------- 1,494,104 1,437,969 Less: Accumulated depreciation 722,189 715,800 ------------- ------------- 771,915 722,169 Construction work in progress 31,636 50,547 ------------- ------------- 803,551 772,716 ------------- ------------- Deferred Debits and Other Assets: Regulatory assets 994,901 1,026,043 Other 67,567 92,280 ------------- ------------- 1,062,468 1,118,323 ------------- ------------- Total Assets $ 2,052,428 $ 2,088,447 ============= ============= The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2003 2002 ---------------- -------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to affiliated companies $ 63,800 $ - Accounts payable 39,614 54,588 Accounts payable to affiliated companies 7,937 4,008 Accrued taxes 16,136 65,317 Accrued interest 11,136 11,333 Unremitted rate reduction bond collections 13,771 25,555 Other 15,308 12,674 -------------- -------------- 167,702 173,475 -------------- -------------- Rate Reduction Bonds 493,011 510,841 -------------- -------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 347,168 359,910 Accumulated deferred investment tax credits 2,388 2,680 Deferred contractual obligations 53,028 56,165 Accrued pension 41,394 37,933 Other 202,550 218,328 -------------- -------------- 646,528 675,016 -------------- -------------- 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 126,684 126,937 Retained earnings 211,279 194,998 Accumulated other comprehensive loss (61) (105) -------------- -------------- Common Stockholder's Equity 337,902 321,830 -------------- -------------- Total Capitalization 745,187 729,115 -------------- -------------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization $ 2,052,428 $ 2,088,447 ============== ============== 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 Six Months Ended June 30, June 30, ------------------------- ----------------------------- 2003 2002 2003 2002 ------------ ----------- ------------- -------------- (Thousands of Dollars) Operating Revenues $ 220,264 $ 248,914 $ 477,159 $ 491,295 ----------- ----------- ----------- ----------- Operating Expenses: Operation - Fuel, purchased and net interchange power 115,395 151,084 252,460 270,423 Other 36,602 31,014 65,508 61,006 Maintenance 23,732 19,342 37,177 32,243 Depreciation 10,720 10,235 21,327 20,304 (Overrecovery)/amortization of regulatory assets, net (13,419) (19,802) 4,151 (5,210) Amortization of rate reduction bonds 9,510 11,173 18,756 26,668 Taxes other than income taxes 8,056 8,864 16,729 18,107 ----------- ----------- ----------- ----------- Total operating expenses 190,596 211,910 416,108 423,541 ----------- ----------- ----------- ----------- Operating Income 29,668 37,004 61,051 67,754 Interest Expense: Interest on long-term debt 3,853 3,983 7,700 8,830 Interest on rate reduction bonds 7,334 7,736 14,744 15,438 Other interest 365 316 612 498 ----------- ----------- ----------- ----------- Interest expense, net 11,552 12,035 23,056 24,766 ----------- ----------- ----------- ----------- Other Loss, Net (1,173) (1,215) (2,384) (1,118) ----------- ----------- ----------- ----------- Income Before Income Tax Expense 16,943 23,754 35,611 41,870 Income Tax Expense 5,889 8,523 13,730 14,910 ----------- ----------- ----------- ----------- Net Income $ 11,054 $ 15,231 $ 21,881 $ 26,960 =========== =========== =========== =========== 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)
Six Months Ended June 30, ------------------------------ 2003 2002 ------------- ------------- (Thousands of Dollars) Operating activities: Net Income $ 21,881 $ 26,960 Adjustments to reconcile to net cash flows (used in)/provided by operating activities: Depreciation 21,327 20,304 Deferred income taxes and investment tax credits, net 3,179 (6,928) Net amortization of recoverable energy costs 11,694 6,647 Amortization/(overrecovery) of regulatory assets, net 4,151 (5,210) Amortization of rate reduction bonds 18,756 26,668 Net other uses of cash (2,277) (25,739) Changes in working capital: Receivables and unbilled revenues, net 11,341 6,231 Fuel, materials and supplies 3,538 3,130 Accounts payable (11,044) 13,129 Accrued taxes (49,181) 13,120 Taxes receivable (16,812) (10,514) Other working capital (excludes cash) (23,305) (2,287) ---------- ---------- Net cash flows (used in)/provided by operating activities (6,752) 65,511 ---------- ---------- Investing Activities: Investments in plant (50,361) (54,976) NU system Money Pool borrowing 86,800 20,400 Buyout/buydown of IPP contracts (20,437) - Other investment activities, net 10,364 (9,252) ---------- ---------- Net cash flows provided by/(used in) investing activities 26,366 (43,828) ---------- ---------- Financing Activities: Issuance of rate reduction bonds - 50,000 Retirement of rate reduction bonds (17,830) (29,224) Net decrease in short-term debt - (15,500) Cash dividends on common stock (5,600) (24,500) Other financing activities, net (98) (3,238) ---------- ---------- Net cash flows used in financing activities (23,528) (22,462) ---------- ---------- Net decrease in cash (3,914) (779) Cash - beginning of period 5,319 1,479 ---------- ---------- Cash - end of period $ 1,405 $ 700 ========== ========== The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES Management's Discussion and Analysis of Financial Condition and Results of Operations PSNH is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management's discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the First Quarter 2003 Form 10-Q, and the NU 2002 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the second quarter of 2003 and for the first six months of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ----------------------------------- Second Six Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenue $(29) (12)% ($14) (3)% Operating Expenses: Fuel, purchased and net interchange power (36) (24) (18) (7) Other operation 6 18 5 7 Maintenance 4 23 5 15 Depreciation - - 1 5 (Overrecovery)/amortization of regulatory assets, net 7 32 9 (a) Amortization of rate reduction bonds (2) (15) (8) (30) Taxes other than income taxes (1) (9) (1) (8) ---- ---- ---- ---- Total operating expenses (22) (10) (7) (2) ---- ---- ---- ---- Operating Income (7) (20) (7) (10) ---- ---- ---- ---- Interest expense, net - - (2) (7) Other loss, net - - (1) (a) ---- ---- ---- ---- Income before income tax expense (7) (29) (6) (15) Income tax expense (3) (31) (1) (8) ---- ---- ---- ---- Net income $ (4) (27)% $ (5) (19)% ==== ==== ==== ==== (a) Percent greater than 100. Comparison of the Second Quarter of 2003 to the Second Quarter of 2002 Operating Revenues Total operating revenues decreased $29 million or 12 percent in the second quarter of 2003 compared with the same period of 2002, due to lower wholesale revenues primarily due to the impact of less owned generation since the sale of Seabrook ($39 million), partially offset by higher retail revenue ($11 million). Retail kWh sales increased by 3.6 percent in 2003. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased $36 million primarily due to lower purchased power expenses as a result of the absence of Seabrook Power contracts costs and lower wholesale sales. Other Operation and Maintenance Other O&M expenses increased $10 million primarily due to higher maintenance costs resulting from fossil production maintenance overhauls ($6 million) and higher administrative cost primarily resulting from higher healthcare costs and lower pension income expense ($5 million), partially offset by lower transmission and distribution expenses ($2 million). (Overrecovery)/Amortization of Regulatory Assets, Net (Overrecovery)/amortization of regulatory assets, net increased $7 million primarily due to increased recovery of stranded costs resulting from the SCRC reconciliation of stranded cost revenues against actual stranded costs. Amortization of Rate Reduction Bonds Amortization of rate reduction bonds decreased $2 million due to the scheduled amortization of principal. Taxes Other Than Income Taxes Taxes other than income taxes decreased $1 million primarily due to lower property tax. Income Tax Expense Income tax expense decreased $3 million primarily due to lower book taxable income. Comparison of the First Six Months of 2003 to the First Six Months of 2002 Operating Revenues Total operating revenues decreased $14 million or 3 percent in the first six months of 2003 compared with the same period of 2002, due to lower wholesale revenues ($44 million), primarily due to the impact of less owned generation since the sale of Seabrook, partially offset by higher retail revenue ($31 million). Retail kWh sales increased by 5.9 percent in 2003. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased $18 million, primarily due to lower purchased power expenses as a result of the absence of Seabrook Power contract costs and lower wholesale sales. Other Operation and Maintenance Other O&M expenses increased $10 million primarily due to higher maintenance costs resulting from fossil production maintenance overhauls ($6 million) and higher administrative cost primarily resulting from lower pension income ($5 million), partially offset by lower transmission and distribution expenses ($3 million). Depreciation Depreciation increased $1 million primarily due to additions to distribution, generation and general plant assets. (Overrecovery)/Amortization of Regulatory Assets, Net (Overrecovery)/amortization of regulatory assets, net increased $9 million primarily due to increased recovery of stranded costs resulting from the SCRC reconciliation of stranded cost revenues against actual stranded costs. Amortization of Rate Reduction Bonds Amortization of rate reduction bonds decreased $8 million due to the scheduled amortization of principal. Taxes Other Than Income Taxes Taxes other than income taxes decreased $1 million primarily due to lower property tax. Interest Expense, Net Interest expense, net decreased $2 million primarily due to lower interest cost associated with the refinancing of the pollution control revenue bonds. Other Loss, Net Other loss, net decreased $1 million primarily due to increased service fees associated with rate reduction bonds and lower gains on the disposition of property in 2003. Income Tax Expense Income tax expense decreased $1 million primarily due to lower book taxable income. LIQUIDITY At June 30, 2003, PSNH had no borrowings outstanding on the Utility Group's $300 million revolving credit line. This credit line matures on November 11, 2003 and management anticipates extending this credit line. Effective May 31, 2003, PSNH bought out the power purchase obligations of 14 small independently owned hydroelectric plants in New Hampshire for $20.4 million paid from cash flows from operations. The buy out payments have been recorded as regulatory assets, and will be recovered, including a return, over the remaining term of the initial contractual arrangements as Part 2 stranded costs. PSNH's net cash flows used in operating activities totaled $6.8 million for the six months ended June 30, 2003, compared with net cash flows provided by operating activities of $65.5 million for the same period of 2002. Cash flows provided by operating activities decreased due to changes in working capital items, primarily the payment of taxes on the gain on the sale of Seabrook. PSNH's net cash flows provided by investing activities were $26.4 million for the six months ended June 30, 2003 compared with net cash flows used in investing activities of $43.8 million for the same period in 2002. The change is primarily due to higher NU system Money Pool borrowings in 2003. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2003 2002 -------------- -------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash $ 1 $ 123 Receivables, net 39,004 42,203 Accounts receivable from affiliated companies 8,565 6,354 Unbilled revenues 10,036 8,944 Fuel, materials and supplies, at average cost 2,341 1,821 Prepayments and other 1,386 1,470 -------------- ------------- 61,333 60,915 -------------- ------------- Property, Plant and Equipment: Electric utility 598,598 590,153 Less: Accumulated depreciation 200,084 195,804 -------------- ------------- 398,514 394,349 Construction work in progress 13,375 11,860 -------------- ------------- 411,889 406,209 -------------- ------------- Deferred Debits and Other Assets: Regulatory assets 252,469 283,702 Prepaid pension 71,256 67,516 Other 19,713 18,304 -------------- ------------- 343,438 369,522 -------------- ------------- Total Assets $ 816,660 $ 836,646 ============== ============= The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2003 2002 ------------- ------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to banks $ - $ 7,000 Notes payable to affiliated companies 79,400 85,900 Accounts payable 17,556 17,730 Accounts payable to affiliated companies 16,547 6,218 Accrued taxes 4,460 4,334 Accrued interest 2,004 2,059 Other 8,714 8,005 ------------- ------------- 128,681 131,246 ------------- ------------- Rate Reduction Bonds 137,769 142,742 ------------- ------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 211,179 222,065 Accumulated deferred investment tax credits 3,494 3,662 Deferred contractual obligations 60,269 63,767 Other 14,466 13,213 ------------- ------------- 289,408 302,707 ------------- ------------- Capitalization: Long-Term Debt 102,282 101,991 ------------- ------------- 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 69,600 69,712 Retained earnings 78,124 77,476 Accumulated other comprehensive loss (70) (94) ------------- ------------- Common Stockholder's Equity 158,520 157,960 ------------- ------------- Total Capitalization 260,802 259,951 ------------- ------------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization $ 816,660 $ 836,646 ============= ============= 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 Six Months Ended June 30, June 30, ---------------------------- ------------------------ 2003 2002 2003 2002 ------------ -------------- ----------- ----------- (Thousands of Dollars) Operating Revenues $ 89,665 $ 87,191 $ 194,451 $ 183,196 ----------- ----------- ----------- ---------- Operating Expenses: Operation - Fuel, purchased and net interchange power 45,164 43,383 98,167 93,583 Other 13,771 14,003 27,541 24,567 Maintenance 3,459 3,313 6,593 6,231 Depreciation 3,515 4,434 6,986 7,623 Amortization of regulatory assets, net 10,899 6,281 22,172 14,185 Amortization of rate reduction bonds 2,459 2,296 4,928 4,891 Taxes other than income taxes 2,837 2,803 5,809 5,743 ----------- ----------- ----------- ---------- Total operating expenses 82,104 76,513 172,196 156,823 ----------- ----------- ----------- ---------- Operating Income 7,561 10,678 22,255 26,373 Interest Expense: Interest on long-term debt 744 527 1,536 1,292 Interest on rate reduction bonds 2,267 2,417 4,575 4,866 Other interest 345 477 721 835 ----------- ----------- ----------- ---------- Interest expense, net 3,356 3,421 6,832 6,993 ----------- ----------- ----------- ---------- Other Loss, Net (222) (2,528) (227) (3,084) ----------- ----------- ----------- ---------- Income Before Income Tax Expense/(Benefit) 3,983 4,729 15,196 16,296 Income Tax Expense/(Benefit) 1,397 (10,593) 6,542 (5,916) ----------- ----------- ----------- ---------- Net Income $ 2,586 $ 15,322 $ 8,654 $ 22,212 =========== =========== =========== ========== The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Six Months Ended June 30, ------------------------------- 2003 2002 ------------- ------------ (Thousands of Dollars) Operating Activities: Net income $ 8,654 $ 22,212 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation 6,986 7,623 Deferred income taxes and investment tax credits, net (9,841) (18,735) Net amortization of recoverable energy costs 299 172 Amortization of regulatory assets, net 22,172 14,185 Amortization of rate reduction bonds 4,928 4,891 Prepaid pension (3,740) (6,050) Net other uses of cash (1,334) (1,599) Changes in working capital: Receivables and unbilled revenues, net (89) 9,742 Fuel, materials and supplies (519) (166) Accounts payable 10,140 (19,499) Accrued taxes 126 (559) Other working capital (excludes cash) 1,144 1,395 ---------- ---------- Net cash flows provided by operating activities 38,926 13,612 ---------- ---------- Investing Activities: Investments in plant (12,276) (10,225) NU system Money Pool (lending)/borrowing (6,500) 27,200 Other investment activities, net (279) 959 ---------- ---------- Net cash flows (used in)/provided by investing activities (19,055) 17,934 ---------- ---------- Financing Activities: Repurchase of common shares - (13,999) Retirement of rate reduction bonds (4,973) (5,132) Net decrease in short-term debt (7,000) (5,000) Cash dividends on common stock (8,006) (8,002) Other financing activities, net (14) (11) ---------- ---------- Net cash flows used in financing activities (19,993) (32,144) ---------- ---------- Net decrease in cash (122) (598) Cash - beginning of period 123 599 ---------- ---------- Cash - end of period $ 1 $ 1 ========== ========== The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY Management's Discussion and Analysis of Financial Condition and Results of Operations WMECO is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management's discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the First Quarter 2003 Form 10-Q, and the NU 2002 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the second quarter of 2003 and the first six months of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ----------------------------------- Second Six Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $ 3 3% $ 11 6% Operating Expenses: Fuel, purchased and net interchange power 2 4 5 5 Other operation - - 3 12 Maintenance - - - - Depreciation (1) (21) (1) (8) Amortization of regulatory assets, net 5 74 8 56 Amortization of rate reduction bonds - - - - Taxes other than income taxes - - - - ---- --- ---- --- Total operating expenses 6 7 15 10 ---- --- ---- --- Operating income (3) (29) (4) (16) ---- --- ---- --- Interest expense, net - - - - Other loss, net 2 91 3 93 ---- --- ---- --- Income before income tax expense/(benefit) (1) (16) (1) (7) Income tax expense/(benefit) 12 (a) 13 (a) ---- --- ---- --- Net income $(13) (83)% $(14) (61)% ==== === ==== === (a) Percent greater than 100. Comparison of the Second Quarter of 2003 to the Second Quarter of 2002 Operating Revenues Operating revenues increased $3 million or 3 percent in 2003, compared with the same period in 2002, due to higher retail revenues ($2 million) and higher wholesale revenues ($1 million). Retail revenues were higher primarily due to an increase in the standard offer component of retail delivery rates and slightly higher sales. Retail kWh sales were 0.5 percent higher. Wholesale revenues were higher primarily due to higher market prices in 2003. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $2 million primarily due to higher standard offer purchases as a result of the higher standard offer contract cost and the retail sales increase. Depreciation Depreciation expense decreased $1 million primarily due to the 2002 adjustment for certain software projects ($1 million). Amortization of Regulatory Assets, Net Amortization of regulatory assets, net expense increased $5 million due to a higher recovery of stranded costs through the stranded cost reconciliation. Other Loss, Net Other loss, net increased $2 million primarily due to the 2002 adjustment to the gain from the 1999 sale of the fossil units as a result of a DTE decision in the annual stranded cost reconciliation filing for the period ending December 31, 1999. Income Tax Expense/(Benefit) Income tax expense/(benefit) increased $12 million primarily due to the recognition in 2002 of investment tax credits as a result of the 2002 DTE stranded cost decision ($13 million). Comparison of the First Six Months of 2003 to the First Six Months of 2002 Operating Revenues Operating revenues increased by $11 million or 6 percent in 2003, compared with the same period in 2002, due to higher retail revenues ($6 million) and higher wholesale revenues ($5 million). Retail revenues were higher primarily due to an increase in the standard offer component of retail delivery rates and higher retail sales. Retail kWh sales were 5 percent higher. Wholesale revenues were higher primarily due to higher market prices in 2003. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $5 million primarily due to higher standard offer purchases as a result of the retail sales increase and the higher standard offer contract cost. Other Operation Other operation expenses increased $3 million primarily due to higher general and administrative expenses resulting from higher healthcare costs and lower pension income. Depreciation Depreciation expense decreased $1 million primarily due to the 2002 adjustment for certain software projects. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net expense increased $8 million primarily due to the higher recovery of stranded costs through the stranded cost reconciliation. Other Loss, Net Other loss, net increased $3 million primarily due to the 2002 adjustment to the gain from the 1999 sale of the fossil units as a result of a DTE decision in the annual stranded cost reconciliation filing for the period ending December 31, 1999. Income Tax Expense/(Benefit) Income tax expense/(benefit) increased $13 million primarily due to the recognition in 2002 of investment tax credits as a result of the 2002 DTE decision. LIQUIDITY At June 30, 2003, WMECO had no borrowings outstanding on the Utility Group's $300 million revolving credit line. This credit line matures on November 11, 2003 and management anticipates extending this credit line. On June 27, 2003, the DTE issued an order allowing WMECO to issue up to $57.5 million of long-term securities on or before December 31, 2003 to refinance short-term debt and cover issuance costs. WMECO is expected to issue that debt in the second half of 2003. WMECO's net cash flows provided by operating activities increased to $38.9 million for the first six months of 2003 from $13.6 million for the same period of 2002. Net cash flows provided by operating activities increased primarily due to changes in working capital items, primarily accounts payable, offset by a decrease in net income of $13.6 million. WMECO's net cash flows used in investing activities were $19.1 million for the six months ended June 30, 2003, compared with net cash flows provided by investing activities of $17.9 million for the same period of 2002. The change is primarily due to lower NU system Money Pool borrowings in 2003. Financing activities decreased in 2003 as a result of the repurchase of common shares in 2002. 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 SEC. These evaluations were made under the supervision and with the participation of management, including the companies' principal executive officer and principal financial officer, as of the end of the period covered by 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 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. Consolidated Edison, Inc. (Con Edison) v. NU - Merger Appeals and Related Litigation A. United States District Court Litigation This litigation consists of the consolidated civil lawsuits filed in the United States District Court for the Southern District of New York (District Court) by Con Edison and NU regarding the parties October 19, 1999 Agreement and Plan of Merger, as amended and restated as of January 11, 2000 (Merger Agreement). In its Amended Complaint, Con Edison alleges that NU failed to perform material obligations under the Merger Agreement, that there has been a "Material Adverse Change" with respect to NU and that certain conditions precedent to Con Edison's obligation to merge with NU have not been and cannot be satisfied. (Con Edison's Amended Complaint further asserts claims for fraud and negligent misrepresentation which were dismissed on summary judgment on March 15, 2003.) In its counterclaim, NU seeks damages in excess of $1 billion alleging that Con Edison is in material breach of the Merger Agreement based on its repudiation thereof and its refusal to proceed with the merger. As of June 19, 2003, the parties' motions in limine had been fully briefed and are now pending before the District Court. Con Edison's July 1, 2003 motion to dismiss NU's "lost premium" counterclaim has also been fully briefed and is pending. On July 24, 2003, Robert Rimkoski filed a motion to intervene. On August 7, 2003, NU filed a brief in opposition to Mr. Rimkoski's motion to intervene. B. Shareholders' Class Action On May 16, 2003, a class action complaint was filed in the Supreme Court of the State of New York on behalf of "all holders of shares of NU common stock as of 4:00 pm on March 5, 2001," as third party beneficiaries of the Merger Agreement seeking compensatory damages, plus interest and costs, against Con Edison for breach of the Merger Agreement. The named plaintiff, Robert Rimkoski, allegedly sold his NU shares on March 7, 2001, two days after Con Edison's refusal to consummate the merger with NU was made public. NU was not named as a party. On June 4, 2003, NU filed a motion to intervene and request for stay of proceedings in the shareholders' class action. Plaintiff Rimkoski has requested that the decision on this motion be postponed pending the outcome of his July 24, 2003 motion to intervene in the aforementioned District Court case. 2. Millstone Station - Damage to Fish Population Lawsuits This litigation involves claims by four fisherman (Maderia, Medeiros, Engelmann and Stepski) against Northeast Nuclear Energy Company (NNECO) and Northeast Utilities Service Company in connection with the operation of Millstone and the alleged damage to their fishing livelihood caused by Millstone's operations as well as claims by a citizen group (Connecticut Coalition Against Millstone) that the National Pollutant Discharge Elimination System permit and related authorizations issued to Millstone by the Connecticut Department of Environmental Protection were invalid and were improperly transferred from NNECO to Dominion Nuclear Connecticut upon the sale of Millstone in 2001. On May 30, 2003, following an order by the court imposing sanctions on plaintiffs relating to discovery issues, plaintiffs' counsel withdrew one of the fisherman cases, claiming it was under duress as a result of coercion by the defendants, their attorney and the court. On June 30, 2003, plaintiffs' counsel requested defendants' consent to reopen the suit and waiver of court- ordered sanctions. Defendants have objected to any such action. A decision by the Connecticut Supreme Court is pending on plaintiffs appeal in the permit transfer matter. 3. NRG - Credit Rating Status On May 14, 2004, NRG and various affiliates filed for Chapter 11 protection in the Federal District Court for the Southern District of New York (Bankruptcy Court). The filing affects various relationships between NU companies and NRG. A. CL&P Standard Offer Service Contract NRG's May 14, 2003 bankruptcy filing included a request by NRG Power Marketing, Inc. (NRG-PM) to terminate service to CL&P under its standard offer supply agreement (SOS Agreement). The Bankruptcy Court authorized NRG- PM to reject the SOS Agreement, but the Federal Energy Regulatory Commission (FERC) has directed NRG-PM to continue to perform under its SOS Agreement until the FERC fully considers the matter. On June 12, 2003, the District Court authorized NRG-PM to cease performance under its SOS Agreement pending the District Court's final order on this matter. On June 25, 2003, the FERC upheld its prior orders stating that the terms of the SOS Agreement do not (at this time) authorize NRG-PM to terminate the SOS Agreement and ordered that a hearing be convened. In the interim, the FERC directed NRG-PM to continue to supply power to CL&P under the SOS Agreement until the FERC determines whether NRG-PM's decision to cease performance was justified. A decision on this matter is expected in October 2003. On June 30, 2003, the District Court vacated its prior decision and concluded that the FERC was the appropriate forum in which to resolve the dispute concerning service under the SOS Agreement, and dismissed NRG-PM's request for authorization to cease performance under the SOS Agreement. On July 3, 2003, NRG-PM petitioned the FERC to stay its June 25, 2003 decision and the FERC denied NRG-PM's motion on July 9, 2003. In addition, on July 8, 2003, NRG-PM petitioned the United States Court of Appeals for the D.C. Circuit to stay the FERC's June 25, 2003 decision ordering NRG-PM to continue to perform under the SOS Agreement. On July 9, 2003, the Official Committee of Unsecured Creditors in the NRG bankruptcy proceeding filed with the United States Court of Appeals for the D.C. Circuit a petition for a writ of mandamus or an injunction requesting that the court direct the FERC to vacate its June 25, 2003 decision (FERC Decision) or to stay the FERC Decision. On July 16, 2003, the United States Court of Appeals for the D.C. Circuit (i) denied NRG's motion to stay the FERC Decision and (ii) denied the Official Committee of Unsecured Creditor's petition for a writ of mandamus or an injunction. On July 18, 2003, NRG-PM filed with the Second Circuit Court of Appeals (i) an appeal of the United States District Court's June 30, 2003 order and (ii) an emergency request for an injunction of the FERC Decision pending the Second Circuit's review of the appeal. On July 18, 2003, the Official Committee of Unsecured Creditors also filed with the Second Circuit Court of Appeals an emergency motion asking that court to stay the FERC Decision. On July 28, 2003, CL&P filed its opposition to the motions of NRG-PM and the Official Committee of Unsecured Creditors. B. Station Service NRG has disputed its responsibility to pay for the provision of station service by CL&P to NRG's Connecticut generating plants. The FERC issued a decision on December 20, 2002 that NRG had agreed that station service from CL&P would be subject to CL&P's applicable retail rates, and that states have jurisdiction over the delivery of power to end users even where, as here, power is not delivered via distribution facilities. NRG refused CL&P's subsequent demand for payment, and on April 3, 2003, CL&P petitioned the Connecticut Department of Public Utility Control (DPUC) for a declaratory order enforcing the FERC's December 20, 2002 decision. The DPUC proceeding is pending, and is currently stayed due to the bankruptcy filing. On June 19, 2003, CL&P petitioned the Bankruptcy Court for relief from the automatic stay provision of the Bankruptcy Code so that CL&P could continue to pursue declaratory relief from the DPUC. NRG is scheduled to file its response to CL&P's petition on July 24, 2003, and a hearing on this matter has been scheduled for August 6, 2003. For additional information on certain matters involving NRG and its affiliates, see "Management's Discussion and Analysis of Financial Condition - NRG Exposures" and Note 4B, "NRG Energy, Inc. Exposures," within the notes to consolidated financial statements included in this combined report on Form 10-Q; "Part II, Item 1. Legal Proceedings" in NU's report on Form 10-Q for the quarter ended March 31, 2003; "Part I, Item 1. Business - Rates and Electric Industry Restructuring - Connecticut Rates and Restructuring" and "Part I, Item 3. Legal Proceedings" in NU's 2002 annual report on Form 10-K. 4. Connecticut Yankee Atomic Power Company Decommissioning Dispute On June 13, 2003, Connecticut Yankee Atomic Power Company (CYAPC) gave notice of the termination of its contract with Bechtel Power Corporation (Bechtel) for the decommissioning of the Connecticut Yankee nuclear power plant. CYAPC terminated the contract, after the failure of settlement discussions that occurred over an eight-month period, due to Bechtel's history of incomplete and untimely performance and refusal to perform remaining decommissioning work. Under the agreement, Bechtel had 30 days to remedy its defaults before the termination became effective. On June 23, 2003, Bechtel filed a complaint against CYAPC in Connecticut Superior Court in Middletown, Connecticut. Bechtel's complaint asserts a number of claims and seeks a variety of remedies, including monetary and punitive damages and rescission of the contract. CYAPC's response to the complaint was due by August 7, 2003. NU's operating subsidiaries collectively own 49 percent of CYAPC, as follows: CL&P - 34.5 percent, PSNH - 5.0 percent and WMECO - 9.5 percent. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS NU. At the Annual Meeting of Shareholders of NU held on May 13, 2003 the following eleven nominees were elected to serve on the Board of Trustees by the votes set forth below: For Withheld Total 1. Richard H. Booth 100,216,327 6,103,987 106,320,314 2. Cotton M. Cleveland 85,248,207 21,072,107 106,320,314 3. Sanford Cloud, Jr. 102,882,936 3,437,378 106,320,314 4. James F. Cordes 102,973,312 3,347,002 106,320,314 5. E. Gail de Planque 100,133,434 6,186,880 106,320,314 6. John H. Forsgren 102,821,277 3,499,037 106,320,314 7. John G. Graham 102,832,280 3,488,034 106,320,314 8. Elizabeth T. Kennan 100,063,326 6,256,988 106,320,314 9. Michael G. Morris 102,277,455 4,042,859 106,320,314 10. Robert E. Patricelli 102,815,001 3,505,313 106,320,314 11. John F. Swope 100,116,272 6,204,042 106,320,314 NU's shareholders also ratified the Board of Trustees' selection of Deloitte & Touche LLP to serve as independent auditors of NU and its subsidiaries for 2003. The vote ratifying such selection was 101,371,839 votes in favor and 4,362,344 votes against, with 586,131 abstentions and broker nonvotes. NU's shareholders also voted to amend the Declaration of Trust of Northeast Utilities to eliminate the provision calling for Northeast Utilities to appoint a transfer agent and registrar for the common shares to be located in Boston, Massachusetts. The vote approving such amendment was 103,806,356 votes in favor and 1,492,217 votes against, with 1,021,741 abstentions and broker nonvotes. NU's shareholders also voted to re-approve the material terms of the performance goals under the Northeast Utilities Incentive Plan. The vote of such re-approval was 97,918,833 votes in favor and 7,102,173 votes against, with 1,299,308 abstentions and broker nonvotes. CL&P. In a written Consent in Lieu of an Annual Meeting of Stockholders of CL&P (Consent) dated June 18, 2003, stockholders voted to fix the number of directors for the ensuing year at three. The vote fixing the number of directors at three was 6,035,205 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of CL&P. Through the Consent, the following three directors were elected, each by a vote of 6,035,205 shares in favor, to serve on the Board of Directors for the ensuing year: David H. Boguslawski, Cheryl W. Grise, and Leon J. Olivier. PSNH. In a written Consent in Lieu of an Annual Meeting of Stockholders of PSNH (Consent) dated June 18, 2003, stockholders voted to fix the number of directors for the ensuing year at five. The vote fixing the number of directors at five was 301 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of PSNH. Through the Consent the following five directors were elected, each by a vote of 301 shares in favor, to serve on the Board of Directors for the ensuing year: David H. Boguslawski, John H. Forsgren, Cheryl W. Grise, Gary A. Long, and Michael G. Morris. WMECO. In a written Consent in Lieu of an Annual Meeting of Stockholders of WMECO (Consent) dated June 18, 2003, stockholders voted to fix the number of directors for the ensuing year at five. The vote fixing the number of directors at five was 434,653 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of WMECO. Through the Consent the following five directors were elected, each by a vote of 434,653 shares in favor, to serve on the Board of Directors for the ensuing year: David H. Boguslawski, John H. Forsgren, Cheryl W. Grise, Kerry J. Kuhlman, and Michael G. Morris. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Listing of Exhibits (NU) Exhibit No. Description ----------- ----------- 3.1.1 Declaration of Trust of NU, as amended through May 13, 2003. (Exhibit 4.1 to NU Form S-8 filed June 11, 2003, File No. 333-106008) 4.1.3.2 Second Supplemental Indenture dated as of June 1, 2003, between NU and the Bank of New York as Trustee, relating to $150 million of Senior Notes, Series B, due 2008. (Exhibit A-1.3 to NU 35-CERT filed June 6, 2003, File No. 70-10051) 15 Deloitte & Touche LLP Letter Regarding Unaudited Financial Information 31 Certification of Michael G. Morris, Chairman, President and Chief Executive Officer of Northeast Utilities, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 8, 2003 31.1 Certification of John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 8, 2003 32 Certification of Michael G. Morris, Chairman, President and Chief Executive Officer of Northeast Utilities (the registrant) 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 August 8, 2003 (a) Listing of Exhibits (CL&P) 31 Certification of Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 8, 2003 31.1 Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 8, 2003 32 Certification of Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power Company and John H. Forsgren, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 8, 2003 (a) Listing of Exhibits (PSNH) 31 Certification of Cheryl W. Grise, Chief Executive Officer of Public Service Company of New Hampshire, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 8, 2003 31.1 Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 8, 2003 32 Certification of Cheryl W. Grise, Chief Executive Officer of Public Service Company of New Hampshire and John H. Forsgren, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 8, 2003 (a) Listing of Exhibits (WMECO) 31 Certification of Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 8, 2003 31.1 Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated August 8, 2003 32 Certification of Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric Company and John H. Forsgren, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 8, 2003 (b) Reports on Form 8-K: NU and CL&P filed current reports on Form 8-K dated May 14, 2003, disclosing: o The filing by NRG and certain of its affiliates, including NRG-PM Inc., of voluntary petitions for reorganization under the bankruptcy code in the southern district of New York. 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: August 8, 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) ------------------------------------------------------------------------------- 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: August 8, 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) 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: August 8, 2003 By /s/ John H. Forsgren -------------- ----------------------------------- John H. Forsgren Executive Vice President and Chief Financial Officer (for the Registrant and as Principal 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: August 8, 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)