10-Q 1 june200210.txt FORM 10-Q SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549-1004 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 2002 ------------- OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________ to ________ Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. ----------- ----------------------------------- ------------------ 1-5324 NORTHEAST UTILITIES 04-2147929 (a Massachusetts voluntary association) 174 Brush Hill Avenue West Springfield, Massachusetts 01090-2010 Telephone: (413) 785-5871 0-11419 THE CONNECTICUT LIGHT AND POWER COMPANY 06-0303850 (a Connecticut corporation) 107 Selden Street Berlin, Connecticut 06037-1616 Telephone: (860) 665-5000 1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 02-0181050 (a New Hampshire corporation) Energy Park 780 North Commercial Street Manchester, New Hampshire 03105-0330 Telephone: (603) 669-4000 0-7624 WESTERN MASSACHUSETTS ELECTRIC COMPANY 04-1961130 (a Massachusetts corporation) 174 Brush Hill Avenue West Springfield, Massachusetts 01090-2010 Telephone: (413) 785-5871 Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date: Company - Class of Stock Outstanding at July 31, 2002 ------------------------ ---------------------------- Northeast Utilities Common shares, $5.00 par value 129,345,783 shares The Connecticut Light and Power Company Common stock, $10.00 par value 6,811,994 shares Public Service Company of New Hampshire Common stock, $1.00 par value 388 shares Western Massachusetts Electric Company Common stock, $25.00 par value 434,653 shares GLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report: COMPANIES CL&P............................ The Connecticut Light and Power Company NAEC............................ North Atlantic Energy Corporation NEON............................ NEON Communications, Inc. NGC............................. Northeast Generation Company NGS............................. Northeast Generation Services Company NU or the company............... Northeast Utilities NU system....................... The Northeast Utilities system companies, including NU and its wholly owned operating subsidiaries: CL&P, PSNH, WMECO, NAEC, and Yankee Gas PSNH............................ Public Service Company of New Hampshire Select Energy................... Select Energy, Inc. SENY............................ Select Energy New York, Inc. SESI............................ Select Energy Services, Inc. WMECO........................... Western Massachusetts Electric Company Yankee.......................... Yankee Energy System, Inc. Yankee Gas...................... Yankee Gas Services Company NUCLEAR UNIT Seabrook........................ Seabrook Unit No. 1, a 1,148 megawatt nuclear electric generating unit completed in 1986; Seabrook went into service in 1990. REGULATORS DPUC............................ Connecticut Department of Public Utility Control DTE............................. Massachusetts Department of Telecommunications and Energy NHPUC........................... New Hampshire Public Utilities Commission OTHER CSC............................. Connecticut Siting Council EITF............................ Emerging Issues Task Force EPS............................. Earnings per share FASB............................ Financial Accounting Standards Board FPPAC........................... Fuel and purchased-power adjustment clause kWh............................. Kilowatt-hour MW.............................. Megawatts NU 2001 Form 10-K............... The NU system combined 2001 Form 10-K as filed with the Securities and Exchange Commission O&M............................. Operation and maintenance SFAS............................ Statement of Financial Accounting Standards Northeast Utilities and Subsidiaries The Connecticut Light and Power Company and Subsidiaries Public Service Company of New Hampshire and Subsidiaries Western Massachusetts Electric Company and Subsidiary TABLE OF CONTENTS ----------------- Page ---- Part I. Financial Information Item 1. 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, 2002 and December 31, 2001.................. 2 Consolidated Statements of Income - Three Months and Six Months Ended June 30, 2002 and 2001............................... 4 Consolidated Statements of Cash Flows - Six Months Ended June 30, 2002 and 2001.............. 5 Management's Discussion and Analysis of Financial Condition and Results of Operations........ 6 Independent Accountants' Report...................... 24 Report of Independent Public Accountants............. 25 Notes to Financial Statements (unaudited - all companies)............................... 26 The Connecticut Light and Power Company and Subsidiaries Consolidated Balance Sheets - June 30, 2002 and December 31, 2001.................. 42 Consolidated Statements of Income - Three Months and Six Months Ended June 30, 2002 and 2001............................... 44 Consolidated Statements of Cash Flows - Six Months Ended June 30, 2002 and 2001.............. 45 Management's Discussion and Analysis of Financial Condition and Results of Operations........ 46 Public Service Company of New Hampshire and Subsidiaries Consolidated Balance Sheets - June 30, 2002 and December 31, 2001................. 52 Consolidated Statements of Income - Three Months and Six Months Ended June 30, 2002 and 2001.............................. 54 Consolidated Statements of Cash Flows - Six Months Ended June 30, 2002 and 2001............. 55 Management's Discussion and Analysis of Financial Condition and Results of Operations....... 56 Western Massachusetts Electric Company and Subsidiary Consolidated Balance Sheets - June 30, 2002 and December 31, 2001................. 62 Consolidated Statements of Income - Three Months and Six Months Ended June 30, 2002 and 2001.............................. 64 Consolidated Statements of Cash Flows - Six Months Ended June 30, 2002 and 2001............. 65 Management's Discussion and Analysis of Financial Condition and Results of Operations....... 66 Item 3. Quantitative and Qualitative Disclosures About Market Risk....................... 69 Part II. Other Information Item 1. Legal Proceedings.............................. 70 Item 4. Submission of Matters to a Vote of Security Holders....................... 71 Item 6. Exhibits and Reports on Form 8-K............... 72 Signatures......................................................... 74 NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2002 2001 -------------- -------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash and cash equivalents............................ $ 94,023 $ 96,658 Investments in securitizable assets.................. 28,885 36,367 Receivables, net..................................... 844,219 831,221 Unbilled revenues.................................... 106,284 126,398 Fuel, materials and supplies, at average cost........ 120,732 108,516 Special deposits..................................... 14,119 13,036 Unrealized net gains on mark-to-market transactions.. 75,530 56,409 Prepayments and other................................ 101,127 69,824 -------------- -------------- 1,384,919 1,338,429 -------------- -------------- Property, Plant and Equipment: Electric utility..................................... 5,909,275 5,743,575 Gas utility.......................................... 657,194 634,884 Competitive energy................................... 994,587 994,901 Other................................................ 199,796 195,741 -------------- -------------- 7,760,852 7,569,101 Less: Accumulated provision for depreciation....... 3,496,147 3,418,577 -------------- -------------- 4,264,705 4,150,524 Construction work in progress........................ 290,578 289,889 Nuclear fuel, net.................................... 26,011 32,564 -------------- -------------- 4,581,294 4,472,977 -------------- -------------- Deferred Debits and Other Assets: Regulatory assets ................................... 3,160,295 3,287,537 Goodwill and other purchased intangible assets, net.. 332,312 333,123 Prepaid pension...................................... 267,448 232,398 Nuclear decommissioning trusts, at market............ 64,127 61,713 Other ............................................... 524,264 468,007 -------------- -------------- 4,348,446 4,382,778 -------------- -------------- Total Assets........................................... $ 10,314,659 $ 10,194,184 ============== ============== The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2002 2001 -------------- -------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to banks............................... $ 290,000 $ 290,500 Long-term debt - current portion..................... 52,063 50,462 Accounts payable..................................... 654,575 622,320 Accrued taxes........................................ 30,910 26,203 Accrued interest..................................... 61,410 35,659 Other................................................ 195,779 161,277 -------------- -------------- 1,284,737 1,186,421 -------------- -------------- Rate Reduction Bonds................................... 2,001,191 2,018,351 -------------- -------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes.................... 1,483,138 1,491,394 Accumulated deferred investment tax credits.......... 113,746 120,071 Deferred contractual obligations..................... 198,353 216,566 Other................................................ 699,714 634,985 -------------- -------------- 2,494,951 2,463,016 -------------- -------------- Capitalization: Long-Term Debt....................................... 2,273,861 2,292,556 -------------- -------------- Preferred Stock...................................... 116,200 116,200 -------------- -------------- Common Shareholders' Equity: Common shares, $5 par value - authorized 225,000,000 shares; 149,271,168 shares issued and 129,773,079 shares outstanding in 2002 and 148,890,640 shares issued and 130,132,136 shares outstanding in 2001............................... 746,356 744,453 Capital surplus, paid in........................... 1,109,741 1,107,609 Deferred contribution plan - employee stock ownership plan................................... (95,501) (101,809) Retained earnings.................................. 678,593 678,460 Accumulated other comprehensive income/(loss)...... 1,383 (32,470) Treasury stock, 15,371,730 shares in 2002 and 14,359,628 shares in 2001.................... (296,853) (278,603) -------------- -------------- Common Shareholders' Equity.......................... 2,143,719 2,117,640 ------------- ------------- Total Capitalization................................... 4,533,780 4,526,396 ------------- ------------- Commitments and Contingencies (Note 2) Total Liabilities and Capitalization................... $ 10,314,659 $ 10,194,184 ============== ============== 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, ------------------------------------------------------------ 2002 2001 2002 2001 -------------- -------------- -------------- -------------- (Thousands of Dollars, except share information) Operating Revenues..................................... $ 1,673,193 $ 1,583,294 $ 3,583,876 $ 3,383,838 -------------- -------------- -------------- -------------- Operating Expenses: Operation - Fuel, purchased and net interchange power......... 1,158,327 1,009,878 2,511,164 2,140,717 Other............................................. 198,724 189,014 396,755 407,942 Maintenance.......................................... 73,449 59,738 125,761 148,419 Depreciation......................................... 50,744 49,891 98,625 110,520 Amortization......................................... 43,038 86,098 113,776 805,954 Taxes other than income taxes........................ 54,860 55,204 129,458 131,091 Gain on sale of utility plant........................ - - - (653,872) -------------- -------------- -------------- -------------- Total operating expenses........................ 1,579,142 1,449,823 3,375,539 3,090,771 -------------- -------------- -------------- -------------- Operating Income....................................... 94,051 133,471 208,337 293,067 Other Income/(Loss), Net............................... 1,653 15,722 (12,344) 172,920 -------------- -------------- -------------- -------------- Income Before Interest Expense and Income Tax (Benefit)/Expense......................... 95,704 149,193 195,993 465,987 -------------- -------------- -------------- -------------- Interest Expense: Interest on long-term debt........................... 37,210 35,243 71,758 78,911 Interest on rate reduction bonds..................... 29,226 26,820 58,788 26,820 Other interest....................................... 2,572 9,482 5,349 33,009 -------------- -------------- -------------- -------------- Interest expense, net........................... 69,008 71,545 135,895 138,740 -------------- -------------- -------------- -------------- Income Before Income Tax (Benefit)/Expense............. 26,696 77,648 60,098 327,247 Income Tax (Benefit)/Expense........................... (3,550) 28,479 9,820 140,779 -------------- -------------- -------------- -------------- Income Before Preferred Dividends of Subsidiaries...... 30,246 49,169 50,278 186,468 Preferred Dividends of Subsidiaries.................... 1,389 2,437 2,779 5,141 -------------- -------------- -------------- -------------- Income Before Cumulative Effect of Accounting Change... 28,857 46,732 47,499 181,327 Cumulative effect of accounting change, net of tax benefit of $14,908.......................... - - - (22,432) -------------- -------------- -------------- -------------- Net Income............................................. $ 28,857 $ 46,732 $ 47,499 $ 158,895 ============== ============== ============== ============== Basic and Fully Diluted Earnings Per Common Share: Income before cumulative effect of accounting change. $ 0.22 $ 0.35 $ 0.37 $ 1.30 Cumulative effect of accounting change, net of tax benefit................................. - - - (0.16) -------------- -------------- -------------- -------------- Basic and Fully Diluted Earnings per Common Share...... $ 0.22 $ 0.35 $ 0.37 $ 1.14 ============== ============== ============== ============== Basic Common Shares Outstanding (average).............. 129,677,793 133,908,739 129,590,899 138,910,719 ============== ============== ============== ============== Fully Diluted Common Shares Outstanding (average)...... 129,993,412 134,149,873 129,871,495 139,256,968 ============== ============== ============== ============== 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, ------------------------------- 2002 2001 --------------- ------------- (Thousands of Dollars) Operating Activities: Income before preferred dividends of subsidiaries........... $ 50,278 $ 186,468 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation.............................................. 98,625 110,520 Deferred income taxes and investment tax credits, net..... (53,089) (120,505) Amortization.............................................. 113,776 805,954 Net amortization/(deferral) of recoverable energy costs... 20,290 (19,051) Gain on sale of utility plant............................. - (653,872) Cumulative effect of accounting change.................... - (22,432) Net other sources/(uses) of cash.......................... 53,282 (8,507) Changes in working capital: Receivables and unbilled revenues, net.................... 7,116 (276,009) Fuel, materials and supplies.............................. (12,217) 61,128 Accounts payable.......................................... 32,255 146,502 Accrued taxes............................................. 4,707 28,944 Investments in securitizable assets....................... 7,482 57,547 Other working capital (excludes cash)..................... 24,722 (91,748) ------------ ------------ Net cash flows provided by operating activities............... 347,227 204,939 ------------ ------------ Investing Activities: Investments in plant: Electric, gas and other utility plant..................... (212,193) (214,227) Nuclear fuel.............................................. (295) (1,092) ------------ ------------ Cash flows used for investments in plant.................... (212,488) (215,319) Investments in nuclear decommissioning trusts............... (4,702) (122,456) Net proceeds from the sale of utility plant................. - 1,035,135 Buyout/buydown of IPP contracts............................. - (1,128,708) Other investment activities, net............................ (47,445) (52,019) ------------ ------------ Net cash flows used in investing activities................... (264,635) (483,367) ------------ ------------ Financing Activities: Issuance of common shares................................... 5,965 1,725 Repurchase of common shares................................. (18,250) (219,237) Issuance of long-term debt.................................. 263,000 263,000 Issuance of rate reduction bonds............................ 50,000 2,118,400 Retirement of rate reduction bonds.......................... (67,160) - Net decrease in short-term debt............................. (500) (854,577) Reacquisitions and retirements of long-term debt............ (282,766) (658,457) Reacquisitions and retirements of preferred stock........... - (60,868) Retirement of monthly income preferred securities........... - (100,000) Retirement of capital lease obligation...................... (180,000) Cash dividends on preferred stock........................... (2,779) (5,141) Cash dividends on common shares............................. (32,379) (28,788) Other financing activities, net............................. (358) - ------------ ------------ Net cash flows (used in)/provided by financing activities..... (85,227) 276,057 ------------ ------------ Net decrease in cash and cash equivalents..................... (2,635) (2,371) Cash and cash equivalents - beginning of period............... 96,658 200,017 ------------ ------------ Cash and cash equivalents - end of period..................... $ 94,023 $ 197,646 ============ ============ 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 2002 Form 10-Q, current reports on Form 8-K dated April 23, 2002, June 17, 2002, July 23, 2002, and August 2, 2002, and the 2001 Form 10-K. FINANCIAL CONDITION Overview Northeast Utilities and subsidiaries (NU or the company) reported earnings of $28.9 million, or $0.22 per share on a fully diluted basis, in the second quarter of 2002, compared with earnings of $46.7 million, or $0.35 per share on a fully diluted basis, in the same period of 2001. For the first six months of 2002, NU reported earnings of $47.5 million, or $0.37 per share on a fully diluted basis compared with earnings of $158.9 million, or $1.14 per share on a fully diluted basis in the same period of 2001. In the first quarter of 2002, NU recorded after-tax charges of $10 million, or $0.08 per share, primarily associated with NU's investment in NEON Communications, Inc. (NEON), a Massachusetts-based provider of high-bandwidth fiber optic telecommunications services. Although NEON filed a reorganization plan in June 2002 in United States Bankruptcy Court in Delaware, NU believes its remaining $5 million investment in NEON is realizable since the plan calls for NU to retain a 7 percent share of NEON's post-bankruptcy equity. Excluding the first quarter charges, NU earned $57.5 million, or $0.45 per share on a fully diluted basis, in the first six months of 2002. In the first six months of 2001, NU recorded several items related to the sale of Millstone nuclear units in March 2001, the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, and the forward repurchase of 10.1 million NU common shares. Absent those items, NU earned $38.7 million, or $0.29 per share on a fully diluted basis, in the second quarter of 2001, and $91.9 million, or $0.67 per share on a fully diluted basis, in the first six months of 2001. The decline in NU's second quarter 2002 earnings is primarily due to weaker results at the competitive energy subsidiaries. In the second quarter of 2002, those businesses lost $9.3 million, compared with earnings of $13.6 million in the second quarter of 2001. These weaker results are related primarily to April 2002 losses on natural gas trading and low early spring river flows, which curtailed production at its conventional hydroelectric plants. Revenues in the first six months of 2002 increased to $3.6 billion from $3.4 billion in the same period of 2001, primarily due to higher sales at NU's competitive energy subsidiaries. Revenues for NU's competitive energy subsidiaries will be reduced as a result of recently released accounting guidance related to the classification of revenues and expenses associated with energy trading contracts. In June 2002, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board reached a consensus on EITF Issue No. 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." The EITF requires energy trading companies to record revenues and expenses associated with energy trading contracts on a net basis, rather than recording the gross revenues and expenses. This change is retroactive to all periods presented, but will have no effect on net income. NU will adopt the statement for the third quarter of 2002. As a result, NU now estimates that its revenues for the first six months of 2002 will be reduced to $2.5 billion from the $3.6 billion reflected in the accompanying consolidated statements of income. Management is in the process of determining the impact EITF Issue No. 02-3 will have on prior periods. NU's 2002 results also declined as a result of lower regulated electric and natural gas sales during the second quarter of 2002 and the first six months of 2002, resulting from mild winter and early spring weather and lower industrial electric sales. Regulated industrial electric sales decreased 10.8 percent in the first six months of 2002, compared with the same periods of 2001. The most significant decline in industrial electric sales was at Public Service Company of New Hampshire (PSNH). All major PSNH industrial sectors experienced sales declines in 2002, but the most significant involved paper products, where one major customer began generating its own electricity and another is in the process of reorganizing. Overall, regulated electric sales decreased 0.9 percent during the second quarter of 2002 and 2.5 percent during the first six months of 2002, compared with the same periods of 2001. Partially offsetting lower sales were lower financing costs and a lower share count. NU had approximately 129.8 million shares outstanding as of June 30, 2002, compared with 133.9 million shares outstanding as of June 30, 2001. NU has repurchased approximately 850,000 shares for the first six months of 2002, and has Board of Trustees authorization to repurchase approximately 10 million additional shares by June 30, 2003. NU repurchased approximately an additional 600,000 shares at an average price of $15.17 through July 31, 2002. Earnings before preferred dividends at The Connecticut Light and Power Company (CL&P), NU's largest regulated subsidiary, totaled $11.4 million in the second quarter of 2002 and $33.1 million in the first six months of 2002, compared with $18.8 million in the second quarter of 2001 and $57.1 million in the first six months of 2001. The lower 2002 earnings were primarily due to an after-tax gain of $19.1 million recorded in the first quarter of 2001 as a result of the Millstone sale. Combined earnings before preferred dividends at PSNH and North Atlantic Energy Corporation (NAEC) totaled $18.1 million in the second quarter of 2002 and $30.8 million in the first six months of 2002, compared with earnings of $19.6 million in the second quarter of 2001 and $54.3 million in the first six months of 2001. The lower 2002 earnings were primarily due to an after-tax gain of $15.5 million recorded in the first quarter of 2001 associated with the sale of PSNH's share of the Millstone 3 nuclear unit and to a greater than 10 percent retail rate reduction that took effect on May 1, 2001, in connection with industry restructuring. Earnings before preferred dividends at Western Massachusetts Electric Company (WMECO) totaled $15.3 million in the second quarter of 2002 and $22.2 million in the first six months of 2002, compared with earnings of $1.5 million in the second quarter of 2001 and earnings of $4.8 million in the first six months of 2001. The higher 2002 earnings were primarily due to the recognition in 2002 of approximately $13 million in tax credits as a result of a regulatory decision received during the second quarter of 2002 and due to a first quarter 2001 refueling outage at the Millstone 3 nuclear unit. Yankee Energy System, Inc. (Yankee) lost $0.5 million in the second quarter of 2002 and earned $12.1 million in the first six months of 2002, compared with a loss of $6.8 million in the second quarter of 2001 and earnings of $8.9 million in the first six months of 2001. The increase in Yankee's earnings during 2002 is primarily due to continued strong control of operation and maintenance (O&M) costs and a reduction in goodwill amortization expense. Future Outlook Despite the weaker results at its competitive energy subsidiaries, NU is maintaining its updated earnings guidance. On June 17, 2002, NU reported that the upper end of its previous earnings range of $1.40 to $1.65 a share was unachievable. NU believes that the lower end of the earnings range remains achievable, excluding significant items such as 1) the $10 million after-tax charges related to NEON and Acumentrics Corporation (Acumentrics), and 2) the expected consolidated after-tax gains of between $25 million and $30 million, related to the proposed sale of the NU system's 40.04 percent ownership interest in the Seabrook nuclear unit and to the elimination of certain Seabrook related reserves. Management anticipates these gains will be recognized during 2002. On April 15, 2002, CL&P, NAEC and certain other unaffiliated joint owners reached an agreement to sell approximately 88.2 percent of the Seabrook nuclear unit to a subsidiary of the FPL Group, Inc. (FPL) for $836.6 million. The aforementioned gain on the sale of Seabrook relates to an agreement between NU and other unaffiliated companies in connection with the sale of those companies' shares of Seabrook. To meet its earnings target, NU needs to have a return to more seasonable weather patterns in its service territories, which has occurred during July 2002, significantly better performance at its competitive energy subsidiaries, regulatory relief on certain outstanding issues and continued strong control of nonfuel O&M costs. Liquidity NU maintained a high level of liquidity throughout the first half of 2002, and maintaining liquidity remains a significant focus for NU. As of June 30, 2002, NU had $94 million in cash and cash equivalents on hand. NU expects its cash position to further improve late in the fourth quarter of 2002 when management expects the sale of CL&P's and NAEC's 40.04 percent share of Seabrook to close. Of the approximately $400 million of total cash proceeds NU expects to receive from the Seabrook sale, a portion of these proceeds will be used to repay all $90 million of NAEC's outstanding debt, return all NAEC's equity, which totaled $38.8 million as of June 30, 2002, to NU and pay between $90 million and $100 million in taxes. Following the sale of NAEC's share of Seabrook, the Seabrook Power Contracts between PSNH and NAEC will be terminated. PSNH will use the proceeds received from NAEC from this contract termination to amortize stranded costs more quickly, repay debt and return additional equity capital to NU. The net gain from the sale related to CL&P's share of Seabrook primarily will be used to offset stranded costs, and the cash proceeds received by CL&P will be used to meet its capital requirements. NU had little financing activity in the second quarter of 2002, other than the refinancing of $263 million of senior unsecured notes on April 4, 2002. The new notes bear interest at 7.25 percent and mature on April 1, 2012. Proceeds from the refinancing were used to redeem a similar amount of variable rate notes that were issued on February 28, 2001. NU's regulated subsidiaries have a $350 million unsecured revolving credit facility under which a total of $120 million was outstanding as of June 30, 2002. This total includes $45 million, $45 million, and $30 million outstanding for PSNH, WMECO and Yankee, respectively. NU parent has a separate $300 million unsecured revolving credit facility under which a total of $80 million of direct borrowings and $114.7 million of letters of credit were outstanding as of June 30, 2002. This total includes $60 million, $10 million, and $10 million advanced by NU parent through the NU System Money Pool to Select Energy, Inc. (Select Energy) Northeast Generation Services Company (NGS) and Select Energy Services, Inc. (SESI), respectively. The $114.7 million represents letters of credit issued to counterparties with whom Select Energy has energy contracts and to other parties. Both the regulated subsidiaries and NU parent revolving credit facilities expire in November 2002. As a result of NU's improved credit ratings and strong liquidity, management does not anticipate any difficulty renewing these credit arrangements. Additionally, NAEC has a separate unsecured term credit agreement for $90 million of which $90 million was outstanding as of June 30, 2002. This term credit agreement expires on November 8, 2002, and may also need to be extended based on the timing of the closing on the sale of Seabrook. NU's net cash flows provided by operating activities increased to $347.2 million in the first six months of 2002, compared with $204.9 million during the same period of 2001. Cash flows provided by operating activities increased primarily due to increased receipts received on accounts receivable balances during the first six months of 2002, compared with the same period of 2001. This increase was partially offset by a $136.2 million decrease in income before preferred dividends. A portion of the decrease in income before preferred dividends does not impact cash flows from operations because the decrease is comprised of certain charges during the first six months of 2002 associated with NEON and Acumentrics and certain items recorded during the first six months of 2001 associated with the adoption of SFAS No. 133, as amended, and the forward purchase of 10.1 million NU common shares. The decrease in income before preferred dividends is also due to weaker results at the competitive energy subsidiaries and lower regulated electric and natural gas sales. Also an increase in payments made on accounts payable balances in the first six months of 2002 compared to the first six months of 2001 resulted in decreasing cash flows from operations. There were fewer investing and financing activities in the first half of 2002, as compared to the same period of 2001, primarily due to the sale of the Millstone units, the buyout and buydown of independent power producer contracts, and the issuance of CL&P, PSNH and WMECO rate reduction certificates and bonds in 2001. The level of NU's common dividends totaled $32.4 million in the first six months of 2002, compared with $28.8 million in the same period of 2001. This increase was a result of NU paying a $0.10 per share quarterly common dividend in the first two quarters of 2001 and a $0.125 per share quarterly common dividend in the last two quarters of 2001 and the first two quarters of 2002, partially offset by a lower share count. On May 14, 2002, NU's Board of Trustees approved payment of a quarterly cash dividend of $0.1375 per share, payable on September 30, 2002, to shareholders of record as of September 1, 2002. This increase is consistent with the company's announced intention of raising the dividend by 10 percent annually with a target payout of 50 percent of regulated company earnings. Such a program will be dependent upon numerous factors, including NU's ability to meet earnings targets and the judgment of its Board of Trustees at the time. For the twelve months ended June 30, 2002, NU's regulated operating companies, CL&P, PSNH, WMECO, NAEC and Yankee Gas Services Company (Yankee Gas) earned $207.8 million. Assuming annualized common dividends of $0.1375 per share and approximately 129.8 million NU common shares outstanding at June 30, 2002, this level of common dividends represents approximately a 34 percent payout of total combined earnings of NU's regulated operating companies. Competitive Energy Subsidiaries NU's competitive energy subsidiaries had a loss of $30.9 million for the first six months of 2002, compared with earnings of $9.4 million before the cumulative effect of an accounting change related to the adoption of SFAS No. 133, as amended, for the first six months of 2001. Unconsolidated revenues for the competitive energy subsidiaries totaled approximately $1.9 billion for the first six months of 2002, compared with $1.3 billion for the first six months of 2001. The increased revenues are primarily the result of increased trading volumes of certain types of energy products and the acquisition of Select Energy New York, Inc. (SENY). For the third quarter of 2002, NU will implement EITF Issue No. 02-3. EITF Issue No. 02-3 requires energy trading companies to record revenues and expenses associated with the energy trading contracts on a net basis, rather than recording the gross revenues and expenses. NU estimates that its competitive energy revenues and expenses for the first six months of 2002 will be reduced to $800 million from the $1.9 billion included in the accompanying consolidated statements of income. CL&P's standard offer purchases from Select Energy represented $304 million of total competitive energy subsidiaries' revenues for the first six months of 2002, compared with $326.7 million for the first six months of 2001. These amounts are eliminated in consolidation. NU's competitive energy subsidiaries own 1,439 megawatts (MW) of generation capacity, consisting of 1,292 MW at Northeast Generation Company (NGC) and 147 MW at Holyoke Water Power Company (HWP). These businesses also include wholesale and retail energy marketing and trading organizations which buy and sell electricity, natural gas, and other fuels. On June 17, 2002, the air circuit breaker in one of NGC's four 270-megawatt pumped storage units at Northfield Mountain was damaged by fire. The unit is expected to remain out of service until late summer, pending repairs to the circuit breaker and the generator. Northfield Mountain's other three units were not damaged and continue to operate. NGC carries property insurance with a $1 million deductible and business interruption insurance that commences after 60 days. As a result, the fire is not expected to have a material effect on NU's or NGC's financial position or results of operations. In the second quarter of 2002, NU conducted studies of the depreciable lives of certain generation and software assets maintained by the competitive energy subsidiaries. The impact of these studies was to lengthen the useful lives of the generation assets by 20 years to an average of 58 remaining years and to shorten the useful lives of the software to 1.5 remaining years effective for the second quarter of 2002. As a result of these studies, NU's consolidated depreciation expense decreased by approximately $1.5 million for the second quarter of 2002 and is expected to decrease by approximately $5.8 million annually. The competitive energy subsidiaries also include SESI, which 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, and NGS, which operates and maintains NGC's and HWP's generation assets and provides third-party contracting services for power plants and large industrial facilities. Consistent with its business strategy, the competitive energy subsidiaries acquired an electrical services company and a telecommunications company in July 2002. These companies are expected to generate approximately $35 million in revenues in 2003. Competitive Energy Subsidiaries' Market and Other Risks NU's competitive energy subsidiaries are exposed to certain market risks inherent in their business activities. Certain competitive energy subsidiaries enter into contracts of varying lengths of time to buy and sell energy commodities, primarily electricity, natural gas and oil. Market risk represents the risk of loss that may impact the subsidiaries' financial statements due to adverse changes in commodity market prices. A significant portion of Select Energy's wholesale marketing business is providing energy to full requirements customers, primarily regulated distribution companies. Under full requirements contract terms, the supplier is required to provide the total energy requirement for the customers' load at all times. A key component of Select Energy's risk management strategy is focused on managing the volume and price risks of full requirements contracts. These risks include significant fluctuations in supply and demand due to numerous factors such as weather, plant availability, transmission congestion, and potentially volatile price fluctuations. Select Energy's first quarter 2002 results were negatively impacted by weather patterns that resulted in contracted supply exceeding demand. Transactions, including the full requirements contracts, intended to be part of Select Energy's normal purchases and sales are recognized on the accrual basis of accounting. The competitive energy subsidiaries manage their portfolio of contracts and assets to maximize value and minimize associated risks. The lengths of contracts to buy and sell energy vary in duration from daily/hourly to several years. At any point in time, as noted previously, the portfolio may be long (purchases exceed sales) or short (sales exceed purchases). Portfolio and risk management disciplines, with established policies and procedures, are used to manage exposures to market risks. At forward market prices in effect at June 30, 2002, the accrual accounting portfolio, which includes the CL&P standard offer contract, had a positive mark-to-market position. There is significant volatility in the energy commodities market. This position fluctuates in value due to changes in energy prices in the region, new transactions entered into during the period and positions settling during the period. Select Energy also engages in the trading of commodity derivatives, which are accounted for using the mark-to-market method under EITF Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities." Energy trading transactions at Select Energy include financial transactions and physical delivery transactions for electricity, natural gas and oil in which Select Energy is attempting to profit from changes in market prices. The company has policies and procedures requiring all trading positions to be marked-to-market daily at the end of each trading day. Controls are in place segregating responsibilities between individuals actually trading (front office) and those verifying the trades (middle office). The mark-to-market calculations are performed by individuals in the middle office independent from the front office. The methods used to mark-to-market energy trading contracts are identified and segregated in the table of fair value of contracts at June 30, 2002. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange futures and options that are marked to closing exchange prices; 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity or natural gas, are marked to the mid-point of bid and ask quotes; and 3) prices based on models or other valuation methods primarily include forwards and options and other transactions for which specific quotes are not available. Long-term electric power prices are modeled using the gas forward curve and estimated heat rate conversions. Broker quotes are available through the year 2005, and models are used for the years 2006 and thereafter. Generally, valuations of short-term contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations based on models or other methods for longer-term contracts are less certain. Accordingly, there is a risk that contracts will not be realized at the amounts recorded. 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, in increasing amounts dependent upon the severity of the decline. At NU's present investment grade ratings, Select Energy has not had to post any collateral based on credit downgrades. Were NU's unsecured ratings to decline two to three notches to sub-investment grade, Select Energy would, under its present contracts, have to provide approximately $88 million of collateral to various counterparties, which NU, under present circumstances, would be able to provide Select Energy from available sources of funds. NU's ratings are currently stable and management does not believe that at this time there is a risk of a ratings downgrade to subinvestment grade levels. The breadth and depth of the market for energy trading and marketing products in Select Energy's market has been adversely affected by the withdrawal or financial weakening of a number of companies who have historically done significant amounts of business with Select Energy. In general, the market for such products has become shorter term in nature, with less liquidity and participants less able to meet Select Energy's credit standards without providing cash or letter of credit support. While Select Energy's core marketing and trading business has not been materially adversely affected by these factors to date, should these trends continue and worsen, there could be some adverse impact on Select Energy's business prospects. As of June 30, 2002, Select Energy had unrealized net gains on mark-to- market transactions of $125 million and unrealized net losses on mark- to-market transactions of $49.5 million on a counterparty-by- counterparty basis. Also as of June 30, 2002, two counterparties collectively represented approximately 37 percent of the unrealized net gains on mark-to-market transactions. Management believes the risk associated with collecting amounts from these counterparties is minimal, primarily due to collateral balances maintained. As of and for the three and six months ended June 30, 2002, the sources of the fair value of these trading contracts and the change in fair value of these trading contracts are as follows: ------------------------------------------------------------------------------- (Millions of Dollars) Fair Value of Contracts at June 30, 2002 ------------------------------------------------------------------------------- Maturity Maturity of Maturity in Total Less than One to Four Excess of Fair Sources of Fair Value One Year Years Four Years Value ------------------------------------------------------------------------------- Prices actively quoted $(2.8) $ 6.5 $ - $ 3.7 Prices provided by external sources 9.5 32.7 15.6 57.8 Prices based on models or other valuation methods (1.9) 3.1 12.8 14.0 ------------------------------------------------------------------------------- Totals $ 4.8 $42.3 $28.4 $75.5 ------------------------------------------------------------------------------- At March 31, 2001, the mark-to-market of contracts maturing in less than one year was negative $6.7 million. During the second quarter of 2002, a significant portion of the negative fair value of contracts as of March 31, 2002, with maturities less than one year was realized. Also during the second quarter of 2002, the availability of external sources of prices to value contracts with maturities in excess of four years decreased as a result of the decrease in liquidity in the market for long-term contracts. Contracts with a fair value of $5.2 million at March 31, 2002, and included at that time in contracts valued with prices provided by external sources are now valued based on models or other valuation methods. The fair value at June 30, 2002, is estimated to be $12.8 million. The $7.6 million change in fair value is included in the table below as a change in fair value attributable to changes in valuation techniques and assumptions. ------------------------------------------------------------------------------- (Millions of Dollars) Total Fair Value ------------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30, 2002 June 30, 2002 ------------------------------------------------------------------------------- Fair value of contracts outstanding at the beginning of the period $57.5 $ 56.4 Contracts realized or otherwise settled during the period 3.4 2.1 Fair value of new contracts when entered into during the period - 11.6 Changes in fair values attributable to changes in valuation techniques and assumptions 7.6 (4.4) Changes in fair value of contracts 7.0 9.8 ------------------------------------------------------------------------------- Fair value of contracts outstanding at the end of the period (June 30, 2002) $75.5 $75.5 ------------------------------------------------------------------------------- During the first three months of 2002, the competitive energy subsidiaries terminated certain long-term energy contracts. Coincident with the terminations, new contracts were entered into with different terms and conditions. These new contracts are derivatives and had a positive mark- to-market of $11.6 million when entered into and $9.5 million as of June 30, 2002. For further information see Note 4, "Market Risk and Risk Management Instruments," and Note 5, "Comprehensive Income," to the consolidated financial statements. Business Development and Capital Expenditures NU's capital expenditures totaled $212.5 million in the first six months of 2002, compared with $215.3 million in the first six months of 2001. NU currently projects year end 2002 capital expenditures to approximate $492 million, approximately $100 million lower than the company had projected at the beginning of 2002. The primary reasons for the lower 2002 capital expenditure projection are delays in commencing work on high voltage electric transmission projects and lower projected capital spending at Yankee Gas. Those changes have been partially offset by increased capital expenditures for CL&P's electric distribution system. In 2001, CL&P announced plans for three high voltage transmission projects in Southwest Connecticut. For the first project, Connecticut Siting Council (CSC) hearings on the replacement of an existing 138,000 volt line between Norwalk, Connecticut and Northport - Long Island, New York were completed in June 2002, and a final decision is expected in late 2002. CL&P currently expects to complete the manufacture and installation of the cable in 2003 and early 2004, respectively. CL&P would share the $80 million cost of this project with the Long Island Power Authority (LIPA), which jointly owns the cable. For the second project, CL&P proposed building a new 345,000 volt transmission line facility along an existing right-of-way between Norwalk, Connecticut and Bethel, Connecticut at an estimated cost of $135 million. The restart of CSC hearings on that project has been postponed until at least November 2002, and a decision is now expected in April 2003. In May 2002, Connecticut Governor John Rowland signed legislation authorizing a moratorium on the approval of additional electric and natural gas transmission crossings of Long Island Sound, which included a delay of decisions on the Bethel to Norwalk project and established task forces to study certain issues associated with siting electric and natural gas lines. As a result, no decision can be made by the CSC any earlier than February 1, 2003. The aforementioned CL&P-LIPA replacement cable is exempt from the moratorium. For the third project, CL&P announced plans for a separate $400 million 345,000 volt transmission line between Norwalk, Connecticut and Middletown, Connecticut. CL&P expects to apply to the CSC for approval of the project in 2003. Restructuring and Rate Matters Connecticut - CL&P: On November 18, 2001, at the request of NRG Power Marketing, Inc. (NRG-PM) which serves 40 percent of the standard offer requirement in 2002, and will serve 45 percent of such load in 2003, CL&P filed a request with the Connecticut Department of Public Utility Control (DPUC) to raise the standard offer service rate from an average of $0.0495 per kilowatt-hour (kWh) to $0.0595 per kWh to help promote competition in advance of the January 1, 2004, termination of the standard offer service period and to provide financial relief to NRG-PM and the other standard offer suppliers including Select Energy. In December 2001, the DPUC rejected CL&P's request, but opened two new dockets to examine the absence of effective retail electric competition in Connecticut and the viability of its standard offer service supply contracts. The first docket culminated in a joint study report issued in a decision by the DPUC on February 15, 2002, which provided the DPUC's and the Office of Consumer Counsel's findings on how to best structure default service and other issues related to electric industry restructuring. The second of the two dockets focused on the viability of the standard offer service contracts. On June 17, 2002, the DPUC concluded "that there does not exist either a legal or factual basis upon which to find probable cause to commence further proceedings regarding the standard offer generation service charge." On July 18, 2002, CL&P, concerned with the financial viability of a major unaffiliated standard offer service supplier, NRG-PM, filed a new proposal with the DPUC to maintain current total rates, but to shift $0.007 per kWh from being used to amortize stranded costs to instead provide additional payments to CL&P's two principal standard offer service suppliers to ensure that there are adequate, available generating units to maintain electric reliability in the near term in Southwest Connecticut. CL&P also proposed to rebid 95 percent of its 2003 standard offer supply requirements to confirm the reasonableness of pricing and to test the market for replacement suppliers. On July 26, 2002, the DPUC denied the requests in CL&P's proposal, indicating that it expects CL&P to enforce the current standard offer contracts. The DPUC also left this docket open to further consider CL&P's requests. CL&P is evaluating NRG-PM's ability to meet its obligations under the standard offer contract based upon two recent developments. NRG Energy, Inc. (NRG), the corporate parent and guarantor of NRG-PM's standard offer contract with CL&P has been downgraded to below the contractually required minimum investment grade level by all three major rating agencies. In addition, NRG's Connecticut generating affiliates, due to various disputes with the State of Connecticut and ISO New England, have threatened to deactivate generating facilities critical to the reliability of supply in the State of Connecticut as early as August 9, 2002. If CL&P is required to seek an alternate source of supply, CL&P would pursue recovery of any additional costs associated with obtaining such supply from NRG-PM pursuant to the contract and may be required to seek DPUC approval to flow through any such costs to customers. Management believes that recovery of these costs is consistent with the provisions of Connecticut's electric utility restructuring legislation. In view of the deterioration of NRG's financial condition, CL&P exercised its contractual right to withhold past due congestion costs from the July standard offer payment to NRG-PM pending the outcome of litigation between the parties concerning contractual liability for congestion costs ongoing in the U.S. District Court for the District of Connecticut. See NU's Form 10-K for 2001, Item 3, "Legal Proceedings", for further information on this litigation. On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale of the Millstone units to Dominion Nuclear Connecticut, Inc. (DNCI). This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale. The company hopes to receive a decision from the DPUC in 2002. On November 23, 2001, CL&P petitioned the DPUC to adjust its stranded costs to account for the announced sale of the Vermont Yankee nuclear unit to an unaffiliated company. On June 12, 2002, the DPUC issued a final decision that found CL&P's request was beneficial to ratepayers and allowed for stranded cost recovery through the Competitive Transition Assessment. On May 17, 2002, CL&P filed an application with the DPUC for the approval of the auction results in the sale of Seabrook to a subsidiary of FPL. The proceeds from the sale of Seabrook will be utilized to offset stranded costs. Hearings were held in July 2002, and a final decision is currently scheduled to be issued in September 2002. Connecticut - Yankee Gas: On May 15, 2002, the DPUC issued a final decision which granted Yankee Gas' motion to terminate the overearnings docket. On August 1, 2002, Yankee Gas filed its first Infrastructure Expansion Rate Mechanism (IERM) filing with the DPUC as directed in the January 30, 2002, rate case decision. Yankee Gas' filing requests approval of a 2003 IERM charge to be reflected on customers' bills effective January 1, 2003. As specified in the rate case decision, Yankee Gas' filing reflects those 2001 through 2003 system expansion projects that Yankee Gas has undertaken or plans to undertake by June 30, 2003, and that meet certain financial criteria outlined by the DPUC. No schedule has yet been assigned to this filing, but a decision is expected on or before January 1, 2003. New Hampshire: The hearings on a docket opened by the New Hampshire Public Utilities Commission (NHPUC) to review PSNH's fuel and purchased-power adjustment clause (FPPAC) concluded in June 2002. At June 30, 2002, PSNH has approximately $179.8 million of recoverable energy costs deferred under the FPPAC, excluding previous deferrals of purchases from independent power producers. Management believes the recovery of these costs is probable and expects the NHPUC will issue its order in the third quarter of 2002. On April 15, 2002, CL&P, NAEC and certain other unaffiliated joint owners reached an agreement to sell approximately 88.2 percent of the Seabrook nuclear unit to a subsidiary of FPL for $836.6 million, including $61.9 million for nuclear fuel. FPL has agreed to assume responsibility for decommissioning the unit and will receive all funds in the Seabrook decommissioning trust. NU and the other unaffiliated joint owners are obligated to top-off their shares of the decommissioning trust if the trust's value does not equal a previously agreed upon level. Approval of the transaction is required from various federal and state regulatory agencies, and the parties are now in the process of obtaining these approvals. Management expects the sale of CL&P's and NAEC's 40.04 percent share of Seabrook to close before the end of 2002. Massachusetts: During the first quarter of 2000, WMECO filed its first annual stranded cost reconciliation filing covering the period March 1, 1998 through December 31, 1999. The Massachusetts Department of Telecommunications and Energy (DTE) issued its decision on this filing on June 7, 2002. The decision included, among other things, a conclusion that investment tax credits associated with generation assets that have been divested did not need to be returned to ratepayers. As a result, WMECO recognized approximately $13 million in tax credits in the second quarter of 2002. On March 30, 2001, WMECO also filed its second annual stranded cost reconciliation with the DTE for calendar year 2000. On March 29, 2002, WMECO filed its 2001 annual transition cost reconciliation with the DTE. This filing reconciles the recovery of stranded generation costs for calendar year 2001. Also included in this filing are the sales proceeds from WMECO's portion of Millstone, the impact of securitization and approximately a $13 million benefit to ratepayers from WMECO's nuclear performance-based ratemaking process. If approved by the DTE, the inclusion of these items as part of the reconciliation filing will allow WMECO to accelerate the recovery of stranded costs. On July 8, 2002, WMECO made a filing in compliance with the DTE's June 7, 2002, decision. This filing included updates to the 2000 and 2001 annual transition cost reconciliation filings. Management anticipates a decision regarding these filings in the second half of 2002. The cumulative deferral of unrecovered stranded costs, as filed through calendar year 2001, is approximately $8.5 million. Management believes these costs are fully recoverable. On July 1, 2002, WMECO completed a competitive bid process for a six- month contract to serve approximately 100 MW of WMECO default service. Affiliate Select Energy was the winner of the bid process and estimates that this contract will result in approximately $13.2 million of revenues. For further information regarding commitments and contingencies related to restructuring and rate matters, see Note 2A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements. Nuclear Plant Performance and Other Matters Seabrook: Seabrook operated at a capacity factor of 83 percent through the first six months of 2002. Seabrook returned to service on June 1, 2002, after the completion of a 28-day scheduled refueling outage that began on May 4, 2002. Excluding the scheduled refueling outage, Seabrook operated at a capacity factor of 99 percent through the first six months of 2002. Seabrook is expected to be sold before the end of 2002. Yankee Companies: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC) consummated the sale of its nuclear generating unit to an unaffiliated company for approximately $180 million. After the repayment of debt and taxes associated with the sale, VYNPC expects to distribute cash proceeds of between $35 million and $40 million to its equity owners. NU subsidiaries CL&P, PSNH and WMECO combined own approximately 17 percent of VYNPC and expect to receive approximately $6 million in proceeds from the sale through a combination of dividends and stock repurchases. Under the terms of the sale, CL&P, PSNH and WMECO will continue to buy approximately 16 percent of the plant's output through March 2012 at a range of fixed prices. Other Matters Critical Accounting Policies: The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates, assumptions and at times difficult, subjective or complex judgments. On January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other Intangible Assets," which required significant estimates, assumptions and judgments in determining reporting units and estimating the fair value of reporting units. For further information regarding the adoption of SFAS No. 142, see Note 3, "Goodwill and Other Intangible Assets," to the consolidated financial statements. Other Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 2, "Commitments and Contingencies," to the consolidated financial statements. Forward Looking Statements: This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancings, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, and other presently unknown or unforeseen factors. RESULTS OF OPERATIONS The components of significant income statement variances for the second quarter of 2002 and the first six months of 2002 are provided in the table below. Income Statement Variances (Millions of Dollars) 2002 over/(under) 2001 ------------------------------------- Second Six Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $ 90 6% $ 200 6% Operating Expenses: Fuel, purchased and net interchange power 148 15 370 17 Other operation 10 5 (11) (3) Maintenance 13 23 (23) (15) Depreciation 1 2 (12) (11) Amortization (43) (50) (692) (86) Taxes other than income taxes - - (1) (1) Gain on sale of utility plant - - 654 100 ---- --- ---- --- Total operating expenses 129 9 285 9 ---- --- ---- --- Operating income (39) (30) (85) (29) ---- --- ---- --- Other income/(loss), net (14) (89) (185) (a) Interest expense, net (2) (4) (3) (2) ---- --- ---- --- Income before income tax expense (51) (66) (267) (82) Income tax expense (32) (a) (131) (93) Preferred dividends of subsidiaries (1) (43) (3) (46) ---- --- ---- --- Income before cumulative effect of accounting change (18) (38) (133) (74) Cumulative effect of accounting change, net of tax benefit - - 22 100 ---- --- ---- --- Net income $(18) (38)% $(111) (70)% ==== === ===== === (a) Percent greater than 100. Comparison of the Second Quarter of 2002 to the Second Quarter of 2001 Operating Revenues Total revenues increased by $90 million or 6 percent in the second quarter of 2002, compared with the same period in 2001, primarily due to higher revenues from the competitive energy companies ($192 million, which reflects eliminations of sales to other NU affiliates), partially offset by lower wholesale revenues for the regulated subsidiaries ($57 million), and lower regulated retail revenues ($30 million). The competitive energy companies' revenue increase is primarily due to higher revenues from Select Energy, primarily as a result of increased trading volumes and the acquisition of SENY. The regulated wholesale revenue decrease is due to lower PSNH wholesale sales and lower wholesale prices ($28 million) and lower sales associated with other purchased-power contracts ($28 million). The regulated retail revenue decrease is due to rate decreases for PSNH and WMECO ($16 million), lower purchased gas adjustment clause revenue for Yankee ($14 million) and lower retail electric sales ($10 million), partially offset by an increase for CL&P resulting from the collection of deferred fuel costs ($10 million). Regulated retail electric kWh sales decreased by 0.9 percent, and firm natural gas volume sales increased by 10.6 percent in the second quarter of 2002. Effective for the third quarter of 2002, management will apply EITF Issue No. 02-3, which requires net reporting of energy trading revenues and expenses. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased in 2002, primarily due to higher purchased energy and capacity costs as a result of higher sales for Select Energy ($201 million, which reflects eliminations of purchases from other NU affiliates), partially offset by lower purchased-power costs for the regulated subsidiaries ($48 million). Effective for the third quarter of 2002, management will apply EITF Issue No. 02-3, which requires net reporting of energy trading revenues and expenses. Other Operation and Maintenance Other O&M expense increased $23 million in the second quarter of 2002, primarily due to higher nuclear expenses as a result of a scheduled outage at the Seabrook unit ($16 million), higher transmission expense ($12 million) and distribution expense ($6 million), partially offset by lower administration and general expense ($5 million) and lower fossil and hydroelectric expense ($4 million). Amortization Amortization decreased in 2002, primarily due to higher amortization in 2001 related to recovery of the Millstone investment ($20 million), the NAEC discontinuance of amortizing Seabrook deferred return in 2001 as a result of PSNH's restructuring ($16 million) and lower amortization in 2002 related to restructuring ($7 million). Other (Loss)/Income, Net Other (loss)/income, net decreased primarily due to NU's 2001 recognition of a noncash gain in connection with the marking to market of NU common shares acquired through forward share repurchase arrangements ($10 million) and the gain on the disposition of property for PSNH in 2001 ($4 million). Income Tax Expense Income tax expense decreased due to WMECO investment tax credits recorded in 2002 ($13 million) and lower taxable income. Comparison of the First Six Months of 2002 to the First Six Months of 2001 Operating Revenues Total revenues increased by $200 million or 6 percent in the first six months of 2002, compared with the same period in 2001, primarily due to higher revenues from the competitive energy companies ($614 million, which reflects eliminations of sales to other NU affiliates), partially offset by lower wholesale revenues for the regulated subsidiaries ($216 million), and lower regulated retail revenues ($170 million). The competitive energy companies' revenue increase is primarily due to higher revenues from Select Energy, primarily as a result of increased trading volumes and the acquisition of SENY. The wholesale revenue decrease is due to lower PSNH wholesale sales and lower wholesale prices ($92 million), the 2001 revenue associated with the sale of Millstone output ($42 million) and lower sales associated with other purchased-power contracts ($82 million). The regulated retail revenue decrease is due to rate decreases for PSNH and WMECO ($60 million), lower purchased gas adjustment clause revenue for Yankee ($57 million) and lower retail sales ($74 million), partially offset by an increase for CL&P resulting from the collection of deferred fuel costs ($21 million). Regulated retail electric kWh sales decreased by 2.5 percent, and firm natural gas volume sales decreased by 9.9 percent in 2002. Effective for the third quarter of 2002, management will apply EITF Issue No. 02-3, which requires net reporting of energy trading revenues and expenses. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased in 2002, primarily due to higher purchased energy and capacity costs as a result of higher sales for Select Energy ($653 million, which reflects eliminations of purchases from other NU affiliates), partially offset by lower purchased-power costs for the regulated subsidiaries ($275 million). Effective for the third quarter of 2002, management will apply EITF Issue No. 02-3, which requires net reporting of energy trading revenues and expenses. Other Operation and Maintenance Other O&M expense decreased $34 million in 2002, primarily due to lower nuclear expenses as a result of the sale of the Millstone units at the end of the first quarter in 2001 ($53 million), lower fossil and hydroelectric expense ($8 million) and lower administration and general expense ($2 million), partially offset by higher transmission expense ($20 million) and distribution costs ($11 million). Depreciation Depreciation decreased in 2002 primarily due to the sale of the Millstone units ($8 million) and PSNH restructuring ($4 million), which began on May 1, 2001. Amortization Amortization decreased in 2002, primarily due to the amortization of the gain in 2001 related to the sale of the Millstone units ($654 million), higher amortization in 2001 related to recovery of the Millstone investment ($50 million) and the NAEC discontinuance of amortizing Seabrook deferred return in 2001 as a result of PSNH's restructuring ($16 million), partially offset by higher amortization related to restructuring ($31 million). Gain on Sale of Utility Plant In 2001, NU recorded gains on the sale of CL&P's and WMECO's ownership interests in the Millstone units. A corresponding amount of amortization expense was recorded. Other (Loss)/Income, Net Other (loss)/income, net decreased primarily due to NU's 2001 recognition of a gain in connection with the sale of Millstone units to DNCI ($202 million pre-tax), a 2002 charge reflecting a write-down in NU's investment in NEON ($15 million pre-tax) and the gain on the disposition of property for PSNH in 2001 ($4 million), partially offset by a 2001 noncash charge related to the forward purchase of NU common shares ($35 million). Income Tax Expense Income tax expense decreased in 2002, primarily due to the recognition of WMECO investment tax credits in the second quarter of 2002 and the tax impacts of the Millstone sale in 2001. Cumulative Effect of Accounting Change, Net of Tax Benefit The cumulative effect of accounting change, net of tax benefit, recorded in 2001, represents the effect of the adoption of SFAS No. 133, as amended ($22 million). INDEPENDENT ACCOUNTANTS' REPORT To the Board of Trustees Northeast Utilities Berlin, Connecticut We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries ("the Company") as of June 30, 2002, and the related condensed consolidated statements of income for the three-month and six-month periods then ended and the related condensed consolidated statement of cash flows for the six-month period then ended. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to such condensed consolidated financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Hartford, Connecticut August 7, 2002 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Northeast Utilities: We have reviewed the accompanying consolidated balance sheet of Northeast Utilities (a Massachusetts trust) and subsidiaries as of June 30, 2001, and the related consolidated statements of income for the three and six-month periods ended June 30, 2001 and 2000 and the consolidated statements of cash flows for the six-month periods ended June 30, 2001 and 2000. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and 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, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States. We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet and consolidated statement of capitalization as of December 31, 2000 and the related consolidated statements of income, comprehensive income, shareholders' equity, cash flows, and income taxes for the year then ended (not presented herein), and, in our report dated January 23, 2001 (except with respect to the matters discussed in Note 15, as to which the date is March 13, 2001), we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2000, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. /s/ Arthur Andersen LLP Arthur Andersen LLP Hartford, Connecticut August 9, 2001 Readers of these consolidated financial statements should be aware that this report is a copy of a previously issued Arthur Andersen LLP report and that this report has not been reissued by Arthur Andersen LLP. Furthermore, this report has not been updated since August 9, 2001, and Arthur Andersen LLP completed its last post-audit review of December 31, 2001, consolidated financial information on May 13, 2002. Northeast Utilities and Subsidiaries The Connecticut Light and Power Company and Subsidiaries Public Service Company of New Hampshire and Subsidiaries Western Massachusetts Electric Company and Subsidiary NOTES TO FINANCIAL STATEMENTS (Unaudited) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies) A. Presentation The accompanying unaudited financial statements should be read in conjunction with the management's discussion and analysis of financial condition and results of operations in this Form 10-Q, the First Quarter 2002 Form 10-Q and the Annual Reports of Northeast Utilities (NU or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), which were filed as part of the NU 2001 Form 10-K, and the current reports on Form 8-K dated April 23, 2002, June 17, 2002, July 23, 2002, and August 2, 2002. The accompanying financial statements contain, in the opinion of management, all adjustments necessary to present fairly NU's and each NU system company's financial position as of June 30, 2002, the results of operations for the three-month and six-month periods ended June 30, 2002 and 2001, and cash flows for the six-month periods ended June 30, 2002 and 2001. All adjustments are of a normal, recurring nature except those described in Notes 1C and 2. Due primarily to the seasonality of NU's business, the results of operations for the three- month and six-month periods ended June 30, 2002 and 2001, and statements of cash flows for the six-month periods ended June 30, 2002 and 2001, are not indicative of the results expected for a full year. The consolidated financial statements of NU and of its subsidiaries, as applicable, include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior period data have been made to conform with the current period presentation. B. Regulatory Accounting and Assets The accounting policies of the NU system regulated operating companies conform to accounting principles generally accepted in the United States applicable to rate-regulated enterprises and reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." CL&P's, PSNH's and WMECO's transmission and distribution businesses continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 to those portions of those businesses continues to be appropriate. Management also believes it is probable that the NU system operating companies will recover their investments in long-lived assets, including regulatory assets. In addition, all material regulatory assets are earning a return. The components of the NU system companies' regulatory assets are as follows: ----------------------------------------------------------------------- June 30, December 31, (Millions of Dollars) 2002 2001 ----------------------------------------------------------------------- Recoverable nuclear costs $ 209.4 $ 231.6 Securitized regulatory assets 1,966.2 2,004.1 Income taxes, net 311.3 312.8 Unrecovered contractual obligations 72.7 78.3 Recoverable energy costs, net 314.2 334.5 Other 286.5 326.2 ----------------------------------------------------------------------- Totals $3,160.3 $3,287.5 ----------------------------------------------------------------------- C. New Accounting Standards Goodwill and Other Intangible Assets: Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other Intangible Assets." For further information regarding the adoption of this standard, see Note 3, "Goodwill and Other Intangible Assets," to the consolidated financial statements. Asset Retirement Obligations: In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires that legal obligations associated with the retirement of property, plant and equipment be recognized as a liability at fair value when incurred when a reasonable estimate of the fair value can be made. SFAS No. 143 is effective for NU's 2003 calendar year, and management is in the process of assessing the impact of SFAS No. 143 on NU's consolidated financial statements. Upon adoption of SFAS No. 143, there may be an impact on NU's consolidated financial statements which management has not determined at this time. Energy Trading and Risk Management Activities: In June 2002, the Emerging Issues Task Force (EITF) of the FASB reached a consensus on EITF Issue No. 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," requiring energy trading companies to classify revenues and expenses associated with certain energy trading contracts on a net basis within revenues, rather than recording the gross revenues and expenses. The application of this consensus will be retroactive to all periods presented but will have no effect on net income. NU will adopt EITF Issue No. 02-3 in the third quarter of 2002. As a result, NU now estimates that its competitive energy revenues and expenses for the first six months of 2002 will be reduced to $800 million from the $1.9 billion reflected in the accompanying NU consolidated statements of income. The reduction in competitive energy revenues and expenses relates to energy trading contracts that physically settle, which are currently recorded as revenues for sales and fuel, purchased and net interchange power for the costs of the sales. A second consensus was reached on EITF Issue No. 02-3 requiring certain additional disclosures the majority of which are included in this Form 10-Q. Management is in the process of determining the impact EITF Issue No. 02-3 will have on prior periods. D. Other (Loss)/Income, Net The components of NU's other (loss)/income, net items are as follows: --------------------------------------------------------------------- For the Six Months Ended --------------------------------------------------------------------- June 30, June 30, (Millions of Dollars) 2002 2001 --------------------------------------------------------------------- Loss on investments $(17.1) $ - Gain related to Millstone sale - 202.2 Loss on share repurchase contracts - (35.4) Other, net 4.8 6.1 --------------------------------------------------------------------- Totals $(12.3) $172.9 --------------------------------------------------------------------- E. Change in Estimated Useful Lives In the second quarter of 2002, NU conducted studies of the depreciable lives of certain generation and software assets maintained by the competitive energy subsidiaries. The impact of these studies was to lengthen the useful lives of the generation assets by 20 years to an average of 58 remaining years and to shorten the useful lives of the software to 1.5 remaining years effective for the second quarter of 2002. As a result of these studies, NU's consolidated depreciation expense decreased by approximately $1.5 million for the second quarter of 2002. 2. COMMITMENTS AND CONTINGENCIES A. Restructuring and Rate Matters (CL&P, PSNH, WMECO) Connecticut: On September 27, 2001, CL&P filed its application with the Connecticut Department of Public Utility Control (DPUC) for approval of the disposition of the proceeds in the amount of $1.2 billion from the sale of the Millstone units to a subsidiary of Dominion Resources, Inc., Dominion Nuclear Connecticut, Inc. This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale. In accordance with Connecticut's electric utility industry restructuring legislation, CL&P was required to utilize any gains from the Millstone sale to offset stranded costs. There are certain contingencies related to this filing regarding the potential disallowance of what management believes were prudently incurred costs. Management believes the recoverability of these costs is probable. The company hopes to receive a decision from the DPUC in 2002. New Hampshire: In July 2001, the New Hampshire Public Utilities Commission (NHPUC) opened a docket to review the fuel and purchased- power adjustment clause (FPPAC) cost accruals between August 2, 1999, and April 30, 2001. Hearings at the NHPUC took place in June 2002, and PSNH filed its closing brief with the NHPUC in July 2002. Under the "Agreement to Settle PSNH Restructuring," FPPAC deferrals are recovered as a Part 3 regulatory asset through a stranded cost recovery charge. At June 30, 2002, PSNH had approximately $179.8 million of recoverable energy costs deferred under the FPPAC, excluding previous deferrals of purchases from independent power producers. Management believes the recoverability of these costs is probable and expects the NHPUC to issue its order in the third quarter of 2002. On June 28, 2002, PSNH made its first stranded cost recovery reconciliation filing with the NHPUC for the period May 1, 2001, through December 31, 2001. This filing reconciles stranded cost revenues against actual stranded cost charges with any difference being recovered or deferred. Included in the stranded cost charges are the net generation revenues and generation costs for the filing period. Where generation revenues exceed costs, additional stranded costs are recovered; where generation costs exceed revenues, costs are deferred for future recovery. The generation costs included in this filing are subject to a prudence review by the NHPUC, and hearings have not yet been scheduled. Management does not expect this prudence review to have a material impact on PSNH's earnings. Massachusetts: During the first quarter of 2000, WMECO filed its first annual stranded cost reconciliation filing covering the period March 1, 1998 through December 31, 1999. The Massachusetts Department of Telecommunications and Energy (DTE) issued its decision on this filing on June 7, 2002. The decision included, among other things, a conclusion that investment tax credits associated with generation assets that have been divested did not need to be returned to ratepayers. As a result, WMECO recognized approximately $13 million in tax credits in the second quarter of 2002. On March 30, 2001, WMECO also filed its second annual stranded cost reconciliation with the DTE for calendar year 2000. On March 29, 2002, WMECO filed its 2001 annual transition cost reconciliation with the DTE. This filing reconciles the recovery of stranded generation costs for calendar year 2001. Also included in this filing are the sales proceeds from WMECO's portion of Millstone, the impact of securitization and approximately a $13 million benefit to ratepayers from WMECO's nuclear performance-based ratemaking process. If approved by the DTE, the inclusion of these items as part of the reconciliation filing will allow WMECO to accelerate the recovery of stranded costs. On July 8, 2002, WMECO made a filing in compliance with the DTE's June 7, 2002, decision. This filing included updates to the 2000 and 2001 annual transition cost reconciliation filings. Management anticipates a decision regarding these filings in the second half of 2002. The cumulative deferral of unrecovered stranded costs, as filed through calendar year 2001, is approximately $8.5 million. Management believes these costs are fully recoverable. B. Long-Term Contractual Arrangements (Select Energy) Select Energy, Inc. (Select Energy) maintains long-term agreements to purchase energy in the normal course of business as part of its portfolio of resources to meet its actual or expected sales commitments. The aggregate amount of these purchase contracts was $5.3 billion at June 30, 2002. These contracts extend through 2006 as follows (millions of dollars): -------------------------------------------------------------------- Year -------------------------------------------------------------------- 2002 $2,947.0 2003 1,763.0 2004 292.4 2005 206.7 2006 61.6 -------------------------------------------------------------------- Total $5,270.7 -------------------------------------------------------------------- 3. GOODWILL AND OTHER INTANGIBLE ASSETS Effective January 1, 2002, NU adopted SFAS No. 142, which ceases amortization of goodwill and certain intangible assets with indefinite useful lives. SFAS No. 142 also requires that goodwill and intangible assets deemed to have indefinite useful lives be reviewed for impairment upon adoption of SFAS No. 142 and at least annually thereafter by applying a fair value-based test. Under SFAS No. 142, goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit exceeds the carrying amount of the goodwill. As of June 30, 2002, NU maintains $313 million of goodwill that is no longer being amortized and $19.3 million of identifiable intangible assets which continue to be amortized up to the maximum useful life of 15 years. These amounts are included on the consolidated balance sheets as goodwill and other purchased intangible assets, net. NU does not maintain any indefinite-lived intangible assets. NU's reporting units that maintain goodwill are generally consistent with the operating segments underlying the reportable segments identified in Note 7, "Segment Information," and are as follows: Yankee Gas Services Company (Yankee Gas), Select Energy Services, Inc. (SESI) and Northeast Generation Services Company (NGS). Yankee Gas is included in the regulated utilities - gas reportable segment and SESI and NGS are included in the competitive energy subsidiaries segment. NU has completed its initial impairment analysis for all reporting units that maintain goodwill and has determined that no impairment exists. In completing this analysis, the fair values of the reporting units were estimated using both discounted cash flow methodologies and an analysis of comparable companies or transactions. A summary of NU's goodwill as of June 30, 2002, by reportable segment and reporting unit is as follows: ------------------------------------------------------ Goodwill (Millions of Dollars) Balance ------------------------------------------------------ Regulated Utilities - Gas: Yankee Gas $287.6 Competitive Energy Subsidiaries: SESI 18.0 NGS 7.0 YESCO 0.4 ------------------------------------------------------ Total $313.0 ------------------------------------------------------ There were no impairments or adjustments to these goodwill balances since January 1, 2002. As of June 30, 2002 and December 31, 2001, NU's intangible assets and related accumulated amortization consisted of the following: ------------------------------------------------------------------------ As of June 30, 2002 ------------------------------------------------------------------------ (Millions of Gross Accumulated Net Dollars) Balance Amortization Balance ------------------------------------------------------------------------ Intangible assets subject to amortization: Exclusively agreement $17.7 $ 3.7 $14.0 Customer list 6.6 1.3 5.3 ------------------------------------------------------------------------ Total $24.3 $ 5.0 $19.3 ------------------------------------------------------------------------ ------------------------------------------------------------------------ As of December 31, 2001 ------------------------------------------------------------------------ (Millions of Gross Accumulated Net Dollars) Balance Amortization Balance ------------------------------------------------------------------------ Intangible assets subject to amortization: Exclusively agreement $17.7 $ 3.1 $14.6 Customer list 6.6 1.1 5.5 ------------------------------------------------------------------------ Total $24.3 $ 4.2 $20.1 ------------------------------------------------------------------------ NU recorded amortization expense of $0.8 million during the first six months of 2002 and 2001, related to these intangible assets. Based on the current amount of intangible assets subject to amortization, the estimated amortization expense for each of the succeeding 5 years from 2002 through 2006 is approximately $1.6 million. These amounts may vary as acquisitions and dispositions occur in the future. The results for the three months and six months ended June 30, 2001, on a historical basis, do not reflect the provisions of SFAS No. 142. Had NU adopted SFAS No. 142 on January 1, 2001, historical net income and basic and fully diluted earnings per share (EPS) amounts would have been adjusted as follows: ------------------------------------------------------------------------ Fully (Millions of Dollars, except Net Basic Diluted share information) Income EPS EPS ------------------------------------------------------------------------ Three Months Ended June 30, 2001: ------------------------------------------------------------------------ Reported net income $46.7 $0.35 $0.35 Add back: goodwill amortization 2.3 0.02 0.02 ----- ----- ----- Adjusted net income $49.0 $0.37 $0.37 ------------------------------------------------------------------------ Three Months Ended June 30, 2002: ------------------------------------------------------------------------ Reported net income $28.9 $0.22 $0.22 ------------------------------------------------------------------------ ------------------------------------------------------------------------ Fully (Millions of Dollars, except Net Basic Diluted share information) Income EPS EPS ------------------------------------------------------------------------ Six Months Ended June 30, 2001: ------------------------------------------------------------------------ Reported net income $158.9 $1.14 $1.14 Add back: goodwill amortization 4.5 0.04 0.03 ------ ----- ----- Adjusted net income $163.4 $1.18 $1.17 ------------------------------------------------------------------------ Six Months Ended June 30, 2002: ------------------------------------------------------------------------ Reported net income $ 47.5 $0.37 $0.37 ------------------------------------------------------------------------ 4. MARKET RISK AND RISK MANAGEMENT INSTRUMENTS (NU, Select Energy, Yankee Gas, Yankee) Derivative Instruments: Effective January 1, 2001, NU adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, the changes in the fair value of those contracts are recognized in accumulated other comprehensive income until the underlying transactions occur. For contracts that meet the definition of a derivative but do not meet the hedging requirements, the changes in fair value of those contracts are recognized currently in earnings. Commodity derivatives that are utilized for trading purposes are accounted for using the mark-to-market method, under EITF Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities," with changes in fair value included in earnings. There have been changes to interpretations of SFAS No. 133 and EITF Issue No. 98-10, and the FASB continues to consider changes and amendments which could affect the recording and disclosure of derivative and hedging activities and trading contracts which are marked-to-market. Competitive Energy Subsidiaries: Select Energy provides both firm requirement energy services to its customers and engages in energy trading and marketing activities. Select Energy manages its exposure to risk from its contractual commitments and provides risk management services to its customers through forward contracts, futures, over-the- counter swap agreements, and options (commodity derivatives). Select Energy has utilized the sensitivity analysis methodology to disclose the quantitative information for its commodity price risks. Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity prices, or other similar price changes. Commodity Price Risk - Trading Activities: As a market participant in the Northeast United States, Select Energy conducts commodity-trading activities in electricity and its related products, natural gas and oil, and therefore, experiences net open positions. Select Energy manages these open positions with strict policies which limit its exposure to market risk and require daily reporting to management of potential financial exposure. Under EITF Issue No. 98-10, these instruments are adjusted to market value, and the unrealized gains and losses are recognized in income in the current period in the consolidated statements of income as fuel, purchased and net interchange power and in the consolidated balance sheets as unrealized net gains on mark-to-market transactions. The net mark-to-market positions at June 30, 2002 and December 31, 2001, were assets of $75.5 million and $56.4 million, respectively. Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity, contract prices and market prices represented by each derivative commodity contract. For swaps, forward contracts and options, market value reflects management's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recorded at market based on closing exchange prices. As of June 30, 2002, Select Energy has calculated the market price resulting from a 10 percent unfavorable change in forward market prices. That 10 percent change would result in approximately a $2.4 million decline in the fair value of the Select Energy trading portfolio. In the normal course of business, Select Energy also faces risks that are either nonfinancial or nonquantifiable. Such risks principally include credit risk, which is not reflected in the aforementioned sensitivity analysis. Commodity Price Risk - Nontrading Derivative Activities: Select Energy utilizes derivative financial and commodity instruments (derivatives), including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas sold under firm commitments with certain customers. Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts, to manage the market risk associated with a portion of its anticipated supply requirements. These derivative instruments have been designated as cash flow hedging instruments. When conducting sensitivity analyses of the change in the fair value of Select Energy's electricity, natural gas and oil nontrading derivatives portfolio, which would result from a hypothetical change in the future market price of electricity, natural gas and oil, the fair values of the contracts are determined from models which take into account estimated future market prices of electricity, natural gas and oil, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments. In most instances, market prices and volatility are determined from quoted prices on the futures exchange. Select Energy has determined a hypothetical change in the fair value for its nontrading derivatives and electricity, natural gas and oil contracts, assuming a 10 percent unfavorable change in forward market prices. As of June 30, 2002, an unfavorable 10 percent change in market price would have resulted in a decline in fair value of approximately $18 million. The impact of a change in electricity, natural gas and oil prices on Select Energy's nontrading derivatives contracts on June 30, 2002, is not necessarily representative of the results that will be realized when these contracts are physically delivered. Select Energy also maintains natural gas service agreements with certain customers to supply gas at fixed prices for terms extending through 2004. Select Energy has hedged its gas supply risk under these agreements through New York Mercantile Exchange (NYMEX) contracts. Under these contracts, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements, which also extend through 2004. As of June 30, 2002, the NYMEX contracts had a notional value of $58.2 million and a mark-to- market asset value of $1.4 million. Regulated Entities: Commodity Price Risk - Nontrading Activities: Yankee Gas maintains a master swap agreement with a financial counterparty to purchase gas at fixed prices. Under this master swap agreement, the purchase price of a specified quantity of gas for two customers is effectively fixed over the term of the gas service agreements with those customers for a period of time not extending beyond 2005. As of June 30, 2002, the commodity swap agreement had a notional value of $13.8 million and a mark-to-market asset value of $0.6 million, which is included in the $1.4 million reported for accumulated other comprehensive income related to hedging activities. Interest Rate Risk - Nontrading Activities: Previously, Yankee Energy System, Inc. (Yankee) entered into an interest rate sensitive derivative. During the second quarter of 2002, Yankee terminated this derivative. The change in the mark-to-market position of this derivative through the termination date in the amount of $0.1 million was included in earnings, as an adjustment to interest expense, as this derivative was determined to be ineffective. Other Interest Rate and Credit Risk Activities: Interest Rate Risk - Nontrading Activities: NU manages its interest rate risk exposure by maintaining a mix of fixed and variable rate debt. As of June 30, 2002, approximately 79 percent of NU's long-term debt, including the current portion, is at a fixed interest rate. The remaining long-term debt is variable-rate and is subject to interest rate risk. Assuming a one percentage point increase in NU's variable interest rates, interest expense would have increased approximately $4.9 million. In addition, NU parent has entered into interest rate sensitive derivatives. NU parent used treasury lock instruments with financial institutions to fix the treasury rate component of the coupon rate on the notes that were issued in April 2002. In April 2002, the agreement ended and NU parent received $5.7 million from the financial institutions. In accordance with SFAS No. 133, the $5.7 million gain, net of tax, will be amortized from accumulated other comprehensive income over the 10-year term of the notes. Credit Risk: Credit risk relates to the risk of loss that NU would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. NU serves a wide variety of customers and suppliers that include independent power producers, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and NU realizes interest receipts and payments related to balances outstanding in these accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms which, in turn, requires NU to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by NU's risk management process. Market risks are monitored regularly by a Risk Oversight Council operating outside of the units that create or actively manage these risk exposures to ensure compliance with NU's stated risk management policies. NU tracks and re-balances the risk in its portfolio in accordance with mark-to-market and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure. NYMEX traded futures and option contracts are guaranteed by the NYMEX and have a lower credit risk. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require an evaluation of potential counterparties' financial conditions (including credit ratings), collateral requirements under certain circumstances (including cash in advance, letters of credit, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to NU entering into trading activities. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact NU's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. 5. COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO) Total comprehensive income, which includes all comprehensive income items, for the NU system is as follows: ------------------------------------------------------------------------ Six Months Ended June 30, ------------------------------------------------------------------------ (Millions of Dollars) 2002 2001 ------------------------------------------------------------------------ NU Consolidated $81.4 $130.7 CL&P 30.4 54.0 PSNH 26.5 42.0 WMECO 22.2 3.7 ------------------------------------------------------------------------ Accumulated other comprehensive (loss)/income mark-to-market adjustments of NU's qualified cash flow hedging instruments are as follows: ------------------------------------------------------------------------ (Millions of Dollars, Net of Tax) ------------------------------------------------------------------------ Balance at January 1, 2002 $(36.9) ------------------------------------------------------------------------ Hedged transactions recognized into earnings 17.5 Change in fair value 19.5 Cash flow transactions entered into for the period 1.3 ------------------------------------------------------------------------ Net change associated with the current period hedging transactions 38.3 ------------------------------------------------------------------------ Total mark-to-market adjustments included in accumulated other comprehensive income at June 30, 2002 $ 1.4 ------------------------------------------------------------------------ Accumulated other comprehensive income items unrelated to NU's qualified cash flow hedging instruments totaled $4.4 million in income and $0.02 million in losses as of January 1, 2002, and June 30, 2002, respectively. 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 diluted EPS: ------------------------------------------------------------------------ (Millions of Dollars, Six Months Ended June 30, except share information) 2002 2001 ------------------------------------------------------------------------ Income before preferred dividends of subsidiaries $50.3 $186.4 Preferred dividends of subsidiaries 2.8 5.1 ------------------------------------------------------------------------ Income before cumulative effect of accounting change $47.5 $181.3 Cumulative effect of accounting change, net of tax benefit - (22.4) ------------------------------------------------------------------------ Net income $47.5 $158.9 ------------------------------------------------------------------------ Basic EPS common shares outstanding (average) 129,590,899 138,910,719 Dilutive effect of employee stock options 280,596 346,249 ------------------------------------------------------------------------ Fully diluted EPS common shares outstanding (average) 129,871,495 139,256,968 ------------------------------------------------------------------------ Basic and fully diluted EPS: Income before cumulative effect of accounting change $0.37 $1.30 Cumulative effect of accounting change, net of tax benefit - (0.16) ------------------------------------------------------------------------ Net income $0.37 $1.14 ------------------------------------------------------------------------ 7. SEGMENT INFORMATION (NU) The NU system is organized between regulated utilities (electric and gas) and competitive energy subsidiaries. The regulated utilities segment represents approximately 56 percent and 73 percent of the NU system's total revenues for the six months ended June 30, 2002 and 2001, respectively, and is comprised of several business units. The implementation of EITF Issue No. 02-3 in the third quarter of 2002 will result in an increase in these percentages. Regulated utilities revenues primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. In 2002, the competitive energy subsidiaries segment had one customer with revenues in excess of 10 percent of its total revenues, CL&P. The purchases by CL&P represented approximately 16 percent of total competitive energy subsidiaries' revenues for the six months ended June 30, 2002. In 2001, the purchases by two customers, one unaffiliated company and CL&P, represented approximately 14 percent and 25 percent, respectively, of total competitive energy subsidiaries' revenues for the six months ended June 30, 2001. The competitive energy subsidiaries segment in the following table includes SESI, a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional electric companies and electric utility companies; Holyoke Water Power Company, a company engaged in the production of electric power; Northeast Generation Company, a corporation that acquires and manages generation facilities; NGS, a corporation that maintains and services any fossil or hydroelectric facility that is acquired or contracted with by NU system companies for fossil or hydroelectric generation services, and Select Energy, a corporation engaged in the trading, marketing, transportation, storage, and sale of energy commodities, at wholesale, in designated geographical areas and in the marketing of energy products to retail customers. Other in the following table includes the results for Mode 1 Communications, Inc., an investor in a fiber-optic communications network. Other also includes the results of the nonenergy related subsidiaries of Yankee. Interest expense included in Other primarily relates to the debt of NU parent. Inter-segment eliminations of revenues and expenses are also included in Other.
----------------------------------------------------------------------------------------- For the Six Months Ended June 30, 2002 ------------------------------------------------------------------------------------------ Regulated Utilities Competitive Eliminations (Millions of ------------------- Energy and Dollars) Electric Gas Subsidiaries Other Total ------------------------------------------------------------------------------------------ Operating revenues $1,857.2 $154.9 $1,886.2 $(314.4) $3,583.9 Operating expenses (1,646.0) (127.6) (1,910.9) 308.9 (3,375.6) ------------------------------------------------------------------------------------------ Operating income/ (loss) 211.2 27.3 (24.7) (5.5) 208.3 Other income/ (loss), net 2.1 - (3.1) (11.3) (12.3) Interest expense, net (93.9) (7.4) (21.8) (12.8) (135.9) Income tax (expense)/ benefit (33.4) (8.0) 18.7 12.9 (9.8) Preferred dividends (2.8) - - - (2.8) ------------------------------------------------------------------------------------------ Net income/(loss) $ 83.2 $ 11.9 $ (30.9) $ (16.7) $ 47.5 ------------------------------------------------------------------------------------------ Total assets $8,019.3 $868.9 $1,748.8 $(322.3) $10,314.7 ------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------ For the Six Months Ended June 30, 2001 ------------------------------------------------------------------------------------------ Regulated Utilities Competitive Eliminations (Millions of ------------------- Energy and Dollars) Electric Gas Subsidiaries Other Total ------------------------------------------------------------------------------------------ Operating revenues $2,219.5 $240.4 $1,324.3 $ (400.4) $ 3,383.8 Operating expenses (1,982.0) (213.8) (1,289.0) 394.0 (3,090.8) ------------------------------------------------------------------------------------------ Operating income/ (loss) 237.5 26.6 35.3 (6.4) 293.0 Other income/ (loss), net 67.3 (0.2) 3.3 102.5 172.9 Interest expense, net (94.8) (7.0) (23.0) (13.9) (138.7) Income tax expense (93.7) (8.8) (6.2) (32.1) (140.8) Preferred dividends (5.1) - - - (5.1) ------------------------------------------------------------------------------------------ Income before cumulative effect of accounting change 111.2 10.6 9.4 50.1 181.3 Cumulative effect of accounting change, net of tax benefit - - (22.0) (0.4) (22.4) ------------------------------------------------------------------------------------------ Net income/(loss) $ 111.2 $ 10.6 $ (12.6) $ 49.7 $ 158.9 ----------------------------------------------------------------------------------------- Total assets $9,155.7 $848.4 $1,333.3 $(1,176.7) $10,160.7 -----------------------------------------------------------------------------------------
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2002 2001 ---------------- ---------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash and cash equivalents............................ $ 2,477 $ 773 Investments in securitizable assets.................. 28,885 36,367 Notes receivable from affiliated companies........... - 77,200 Receivables, net..................................... 254,601 247,801 Accounts receivable from affiliated companies........ 18,771 22,134 Unbilled revenues.................................... 4,799 7,492 Fuel, materials and supplies, at average cost........ 32,918 33,085 Prepayments and other................................ 12,271 17,703 ---------------- --------------- 354,722 442,555 ---------------- --------------- Property, Plant and Equipment: Electric utility..................................... 3,216,946 3,127,548 Less: Accumulated provision for depreciation...... 1,267,240 1,236,638 ---------------- --------------- 1,949,706 1,890,910 Construction work in progress........................ 137,200 134,964 Nuclear fuel, net.................................... 2,648 3,299 ---------------- --------------- 2,089,554 2,029,173 ---------------- --------------- Deferred Debits and Other Assets: Regulatory assets.................................... 1,784,549 1,877,191 Prepaid pension...................................... 260,142 233,692 Nuclear decommissioning trusts, at market............ 6,508 6,231 Other ............................................... 170,966 138,715 ---------------- --------------- 2,222,165 2,255,829 ---------------- --------------- Total Assets........................................... $ 4,666,441 $ 4,727,557 ================ ================ The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2002 2001 ---------------- ---------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to affiliated companies................. $ 28,250 $ - Accounts payable...................................... 132,453 132,593 Accounts payable to affiliated companies.............. 82,088 85,057 Accrued taxes......................................... 20,940 34,823 Accrued interest...................................... 29,393 10,369 Other................................................. 49,303 47,342 ---------------- ---------------- 342,427 310,184 ---------------- ---------------- Rate Reduction Bonds.................................... 1,325,850 1,358,653 ---------------- ---------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes..................... 784,584 820,444 Accumulated deferred investment tax credits........... 94,695 95,996 Deferred contractual obligations...................... 129,288 141,497 Other................................................. 320,098 283,399 ---------------- ---------------- 1,328,665 1,341,336 ---------------- ---------------- Capitalization: Long-Term Debt........................................ 826,187 824,349 ---------------- ---------------- Preferred Stock....................................... 116,200 116,200 ---------------- ---------------- Common Stockholder's Equity: Common stock, $10 par value - authorized 24,500,000 shares; 6,811,994 shares outstanding in 2002 and 7,584,884 shares outstanding in 2001... 68,120 75,849 Capital surplus, paid in............................ 369,927 414,018 Retained earnings................................... 288,922 286,901 Accumulated other comprehensive income.............. 143 67 ---------------- ---------------- Common Stockholder's Equity........................... 727,112 776,835 ---------------- ---------------- Total Capitalization.................................... 1,669,499 1,717,384 ---------------- ---------------- Commitments and Contingencies (Note 2) Total Liabilities and Capitalization.................... $ 4,666,441 $ 4,727,557 ================ ================ The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Six Months Ended June 30, June 30, ---------------------------------------------------- 2002 2001 2002 2001 ---------------------------------------------------- (Thousands of Dollars) Operating Revenues.................................. $ 581,731 $ 610,275 $ 1,186,151 $ 1,344,180 ---------------------------------------------------- Operating Expenses: Operation - Fuel, purchased and net interchange power....... 344,497 337,164 703,197 763,966 Other........................................... 78,564 73,081 148,776 171,625 Maintenance........................................ 17,744 18,909 32,268 65,753 Depreciation....................................... 26,110 22,204 49,406 51,108 Amortization of regulatory assets, net............. 39,107 60,773 64,146 619,016 Taxes other than income taxes...................... 30,181 30,030 78,719 70,226 Gain on sale of utility plant...................... - - - (530,724) ---------------------------------------------------- Total operating expenses......................... 536,203 542,161 1,076,512 1,210,970 ---------------------------------------------------- Operating Income..................................... 45,528 68,114 109,639 133,210 Other Income, Net.................................... 2,704 5,246 6,183 31,221 ---------------------------------------------------- Income Before Interest and Income Tax Expense........ 48,232 73,360 115,822 164,431 ---------------------------------------------------- Interest Expense: Interest on long-term debt......................... 11,137 14,454 22,333 35,784 Interest on rate reduction bonds................... 19,073 20,577 38,484 20,577 Other interest..................................... (431) (259) (629) 984 ---------------------------------------------------- Interest expense, net............................ 29,779 34,772 60,188 57,345 ---------------------------------------------------- Income Before Income Tax Expense..................... 18,453 38,588 55,634 107,086 Income Tax Expense................................... 7,046 19,776 22,543 49,974 ---------------------------------------------------- Net Income........................................... $ 11,407 $ 18,812 $ 33,091 $ 57,112 ==================================================== 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, ----------------------------------- 2002 2001 ---------------- ------------- (Thousands of Dollars) Operating Activities: Net income........................................................ $ 33,091 $ 57,112 Adjustments to reconcile to net cash flows provided by/(used in) operating activities: Depreciation..................................................... 49,406 51,108 Deferred income taxes and investment tax credits, net............ (34,857) (127,859) Net amortization/(deferral) of recoverable energy costs.......... 14,452 (1,269) Amortization of regulatory assets, net........................... 64,146 619,016 Gain on sale of utility plant.................................... - (530,724) Net other sources/(uses) of cash................................. 19,202 (78,293) Changes in working capital: Receivables and unbilled revenues, net........................... (744) (160,525) Fuel, materials and supplies..................................... 167 2,707 Accounts payable................................................. (3,109) (26,700) Accrued taxes.................................................... (13,971) 46,927 Investments in securitizable assets.............................. 7,482 57,547 Other working capital (excludes cash)............................ 26,543 38,248 -------------- -------------- Net cash flows provided by/(used in) operating activities............ 161,808 (52,705) -------------- -------------- Investing Activities: Investments in plant: Electric utility plant........................................... (103,041) (113,734) Nuclear fuel..................................................... (39) (648) -------------- -------------- Cash flows used for investments in plant........................... (103,080) (114,382) Investment in NU system Money Pool................................. 105,450 (139,100) Investments in nuclear decommissioning trusts...................... (579) (95,263) Net proceeds from the sale of utility plant........................ - 832,353 Buyout/buydown of IPP contracts.................................... - (1,029,008) Other investment activities, net................................... (46,020) (35,530) -------------- -------------- Net cash flows used in investing activities.......................... (44,229) (580,930) -------------- -------------- Financing Activities: Repurchase of common shares........................................ (49,996) - Issuance of rate reduction bonds................................... - 1,438,400 Retirement of rate reduction bonds................................. (32,803) - Net decrease in short-term debt.................................... - (115,000) Reacquisitions and retirements of long-term debt................... - (416,000) Retirement of monthly income preferred securities.................. - (100,000) Retirement of capital lease obligation............................. - (145,800) Cash dividends on preferred stock.................................. (2,779) (2,779) Cash dividends on common stock..................................... (30,036) (30,036) Other financing activities, net.................................... (261) - -------------- -------------- Net cash flows (used in)/provided by financing activities............ (115,875) 628,785 -------------- -------------- Net increase/(decrease) in cash and cash equivalents................. 1,704 (4,850) Cash and cash equivalents - beginning of period...................... 773 5,461 -------------- -------------- Cash and cash equivalents - end of period............................ $ 2,477 $ 611 ============== ============== 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 2002 Form 10-Q, the current report on Form 8-K dated June 17, 2002, and the NU 2001 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the second quarter of 2002 and the first six months of 2002 are provided in the table below. Income Statement Variances (Millions of Dollars) 2002 over/(under) 2001 ------------------------------------- Second Six Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $(29) (5)% $(158) (12)% Operating Expenses: Fuel, purchased and net interchange power 7 2 (61) (8) Other operation 6 8 (23) (13) Maintenance (1) (6) (33) (51) Depreciation 4 18 (2) (3) Amortization (22) (36) (555) (90) Taxes other than income taxes - - 8 12 Gain on sale of utility plant - - 531 100 ---- --- ----- --- Total operating expenses (6) (1) (135) (11) ---- --- ----- --- Operating income (23) (33) (23) (18) ---- --- ----- --- Other income, net (2) (48) (25) (80) Interest expense, net (5) (14) 3 5 ---- --- ----- --- Income before income tax expense (20) (52) (51) (48) Income tax expense (13) (64) (27) (55) ---- --- ----- --- Net income $ (7) (39)% $ (24) (42)% ==== === ===== === (a) Percent greater than 100. Comparison of the Second Quarter of 2002 to the Second Quarter of 2001 Operating Revenues Operating revenues decreased by $29 million or 5 percent in the second quarter of 2002, primarily due to lower wholesale revenues of $24 million. Wholesale revenues were lower primarily due to lower revenue from market based contracts ($9 million), lower sales of energy and capacity ($8 million), and lower sales of Seabrook and Vermont Yankee generating capacity ($6 million). Retail sales for the second quarter were relatively flat compared to the same period in 2001. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased in the second quarter of 2002, primarily due to the 2002 amortization of deferred fuel expenses which are being recovered. Other Operation and Maintenance Other operation and maintenance (O&M) expense increased by $5 million in the second quarter of 2002, primarily due to higher transmission expenses ($5 million) and higher administrative and general expenses ($4 million), partially offset by lower distribution expenses ($2 million). Depreciation Depreciation expense increased in the second quarter of 2002, due to higher utility plant balances ($2 million) and an estimate adjustment recorded in the second quarter of 2002 for certain software projects ($2 million). Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased in the second quarter of 2002 due to lower amortization of the nuclear investment. Other Income, Net Other income, net decreased in the second quarter of 2002, primarily due to lower interest and dividend income ($5 million). Interest Expense, Net Interest expense decreased in the second quarter of 2002, primarily due to the reacquisitions and retirements of long-term debt in 2001, and lower interest paid on rate reduction bonds. Income Tax Expense Income tax expense decreased in the second quarter of 2002 due to lower book taxable income. Comparison of the First Six Months of 2002 to the First Six Months of 2001 Operating Revenues Operating revenues decreased by $158 million or 12 percent in 2002, primarily due to lower wholesale revenues ($133 million) and lower retail revenues due to lower sales ($24 million). Wholesale revenues were lower due to the sale of the Millstone units in the first quarter of 2001 ($62 million), lower revenues from sales of energy and capacity ($46 million), lower revenue from market based contracts ($19 million), and lower sales of Seabrook and Vermont Yankee generating capacity ($9 million). Retail sales were 1.9 percent lower than last year due to mild weather in the first quarter of 2002. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased by $61 million in 2002, due to lower purchased-power costs resulting from the buydown and buyout of various cogeneration contracts ($73 million) and lower nuclear fuel expense ($7 million), partially offset by the 2002 amortization of deferred fuel expenses which are being recovered ($23 million). Other Operation and Maintenance Other O&M expense decreased by $56 million in 2002, primarily due to lower nuclear expenses as a result of the sale of the Millstone units at the end of the first quarter of 2001 ($55 million). Depreciation Depreciation expense decreased in 2002 due to the 2001 sale of the Millstone units ($5 million), partially offset by higher non-nuclear utility plant balances in 2002 and an estimate adjustment recorded in the second quarter of 2002 for certain software projects ($3 million). Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased in 2002, primarily due to higher amortization in 2001 related to the sale of the Millstone units ($531 million), and lower amortization of the nuclear investment ($36 million), partially offset by higher amortization of securitized regulatory assets ($30 million). Taxes Other Than Income Taxes Taxes other than income taxes increased in 2002, primarily due to the DPUC's order for CL&P to compensate the Town of Waterford for its loss of property tax revenue resulting from electric utility restructuring ($17 million), partially offset by decreases in payroll taxes ($4 million) and local property taxes ($3 million). CL&P is recovering through rates the additional property tax payments to the Town of Waterford. Gain on Sale of Utility Plant In 2001, CL&P recorded a gain on the sale of its ownership share in the Millstone units. A corresponding amount of amortization expense was recorded. Other Income, Net Other income, net decreased in 2002, primarily due to the gain recognized in 2001 on the sale of the Millstone units ($29 million). Interest Expense, Net Interest expense increased in 2002, primarily due to the interest paid on rate reduction bonds, partially offset by lower interest on other long-term debt resulting from reacquisitions and retirements of long- term debt in 2001. Income Tax Expense Income tax expense decreased in 2002 primarily due to lower book taxable income. LIQUIDITY CL&P expects its cash position to further improve late in the fourth quarter of 2002 when management expects the sale of CL&P's 4.06 percent share of Seabrook to close. The net gain from the sale related to CL&P's share of Seabrook primarily will be used to offset stranded costs, and the cash proceeds received by CL&P will be used to meet its capital requirements. NU's regulated subsidiaries, including CL&P, have a $350 million unsecured revolving credit facility under which a total of $120 million was outstanding as of June 30, 2002. CL&P did not have any borrowings outstanding under this facility as of June 30, 2002. This revolving credit facility expires in November 2002. As a result of NU's improved credit ratings and strong liquidity, management does not anticipate any difficulty renewing this credit arrangement. CL&P's net cash flows provided by operating activities increased to $161.8 million in the first six months of 2002, compared with net cash flows used in operating activities of $52.7 million during the same period of 2001. Cash flows provided by operating activities increased primarily due to increased receipts received on accounts receivable balances during the first six months of 2002, compared with the same period of 2001. Additionally, decreased payments made on accounts payable balances in the first six months of 2002 also increased cash flows provided by operating activities. These increases were partially offset by a $24 million decrease in net income in 2002. There were fewer investing and financing activities in the first half of 2002, as compared to the same period of 2001, primarily due to the sale of the Millstone units, the buyout and buydown of independent power producer contracts and the issuance of rate reduction certificates in 2001. The level of common dividends totaled $30 million in the first six months of 2002 and 2001. Payment of these common dividends, as well as a common share repurchase in the amount of $50 million in 2002, helped to finance NU's share repurchases and common dividend. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2002 2001 ---------------- --------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash................................................. $ 700 $ 1,479 Receivables, net..................................... 78,696 70,540 Accounts receivable from affiliated companies........ 18 13,055 Taxes receivable..................................... 10,513 - Unbilled revenues.................................... 27,919 29,268 Fuel, materials and supplies, at average cost........ 38,918 42,047 Prepayments and other................................ 24,783 10,211 ----------- ----------- 181,547 166,600 ----------- ----------- Property, Plant and Equipment: Electric utility..................................... 1,506,709 1,447,955 Other................................................ 6,221 6,221 ----------- ----------- 1,512,930 1,454,176 Less: Accumulated provision for depreciation...... 706,013 689,397 ----------- ----------- 806,917 764,779 Construction work in progress........................ 35,656 44,961 ----------- ----------- 842,573 809,740 ----------- ----------- Deferred Debits and Other Assets: Regulatory assets.................................... 1,029,670 1,046,760 Other ............................................... 91,649 71,414 ----------- ----------- 1,121,319 1,118,174 ----------- ----------- Total Assets........................................... $2,145,439 $2,094,514 =========== =========== The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2002 2001 ---------------- ---------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to banks................................ $ 45,000 $ 60,500 Notes payable to affiliated companies................. 43,400 23,000 Obligations under Seabrook Power Contracts and other capital leases - current portion.......... 21,459 24,164 Accounts payable...................................... 45,335 32,285 Accounts payable to affiliated companies.............. 18,806 18,727 Accrued taxes......................................... 15,401 2,281 Accrued interest...................................... 12,217 9,428 Overcollections on rate reduction bonds............... 23,725 12,479 Other................................................. 11,436 12,685 ---------------- ---------------- 236,779 195,549 ---------------- ---------------- Rate Reduction Bonds.................................... 528,157 507,381 ---------------- ---------------- Obligations under Seabrook Power Contracts and Other Capital Leases.............................. 85,578 86,111 ---------------- ---------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes..................... 419,244 423,050 Accumulated deferred investment tax credits........... 7,347 12,015 Deferred contractual obligations...................... 34,981 37,712 Accrued pension....................................... 37,226 37,326 Other................................................. 45,183 46,260 ---------------- ---------------- 543,981 556,363 ---------------- ---------------- Capitalization: Long-Term Debt........................................ 407,285 407,285 ---------------- ---------------- Common Stockholder's Equity: Common stock, $1 par value - authorized 100,000,000 shares; 388 shares outstanding in 2002 and 2001................................... - - Capital surplus, paid in............................ 164,193 165,000 Retained earnings................................... 179,561 176,419 Accumulated other comprehensive (loss)/income....... (95) 406 ---------------- ---------------- Common Stockholder's Equity........................... 343,659 341,825 ---------------- ---------------- Total Capitalization.................................... 750,944 749,110 ---------------- ---------------- Commitments and Contingencies (Note 2) Total Liabilities and Capitalization.................... $ 2,145,439 $ 2,094,514 ================ ================ The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Six Months Ended June 30, June 30, ------------------------------------------------ 2002 2001 2002 2001 ------------------------------------------------ (Thousands of Dollars) Operating Revenues.................................. $ 248,914 $ 286,799 $ 491,295 $ 627,634 ------------------------------------------------ Operating Expenses: Operation - Fuel, purchased and net interchange power....... 151,084 181,083 270,423 418,763 Other........................................... 31,014 33,096 61,006 63,995 Maintenance........................................ 19,342 19,304 32,243 34,794 Depreciation....................................... 10,235 11,296 20,304 21,810 Amortization of regulatory assets, net............. (8,629) 1,438 21,458 12,905 Taxes other than income taxes...................... 8,864 9,574 18,107 21,138 ------------------------------------------------ Total operating expenses......................... 211,910 255,791 423,541 573,405 ------------------------------------------------ Operating Income..................................... 37,004 31,008 67,754 54,229 Other (Loss)/Income, Net............................. (1,215) 4,393 (1,118) 38,488 ------------------------------------------------ Income Before Interest and Income Tax Expense........ 35,789 35,401 66,636 92,717 ------------------------------------------------ Interest Expense: Interest on long-term debt......................... 5,388 7,413 11,367 15,015 Interest on rate reduction bonds................... 6,572 5,334 13,498 5,334 Other interest..................................... 75 (126) (99) (187) ------------------------------------------------ Interest expense, net............................ 12,035 12,621 24,766 20,162 ------------------------------------------------ Income Before Income Tax Expense..................... 23,754 22,780 41,870 72,555 Income Tax Expense................................... 8,523 7,263 14,910 28,676 ----------------------------------- ----------- Net Income........................................... $ 15,231 $ 15,517 $ 26,960 $ 43,879 =================================== =========== 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, ----------------------------- 2002 2001 ------------ ------------ (Thousands of Dollars) Operating activities: Net income........................................................ $ 26,960 $ 43,879 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation.................................................... 20,304 21,810 Deferred income taxes and investment tax credits, net........... (6,928) 186,753 Net amortization/(deferral) of recoverable energy costs, net.... 6,647 (28,300) Amortization of regulatory assets, net.......................... 21,458 12,905 Gain on sale of utility plant................................... - (25,012) Net other (uses)/sources of cash................................ (25,739) 8,942 Changes in working capital: Receivables and unbilled revenues, net.......................... 6,231 (2,628) Fuel, materials and supplies.................................... 3,130 (11,089) Accounts payable................................................ 13,129 176,181 Accrued taxes................................................... 13,120 16,675 Taxes receivable................................................ (10,514) (202,403) Other working capital (excludes cash)........................... (2,287) (3,930) ------------ ------------ Net cash flows provided by operating activities..................... 65,511 193,783 ------------ ------------ Investing Activities: Investments in plant: Electric utility plant.......................................... (54,976) (46,332) Nuclear fuel.................................................... - (37) ------------ ------------ Cash flows used for investments in plant.......................... (54,976) (46,369) Investment in NU system Money Pool................................ 20,400 26,200 Investments in nuclear decommissioning trusts..................... - (1,625) Other investment activities, net.................................. (9,252) (4,825) ------------ ------------ Net cash flows used in investing activities......................... (43,828) (26,619) ------------ ------------ Financing Activities: Repurchase of common shares....................................... - (260,000) Issuance of rate reduction bonds.................................. 50,000 525,000 Retirement of rate reduction bonds................................ (29,224) - Net decrease in short-term debt................................... (15,500) - Reacquisitions and retirements of preferred stock................. - (24,268) Buydown of capital lease obligation............................... - (497,508) Cash dividends on preferred stock................................. - (1,286) Cash dividends on common stock.................................... (24,500) (18,000) Other financing activities, net................................... (3,238) - ------------ ------------ Net cash flows used in financing activities......................... (22,462) (276,062) ------------ ------------ Net decrease in cash................................................ (779) (108,898) Cash - beginning of period.......................................... 1,479 115,135 ------------ ------------ Cash - end of period................................................ $ 700 $ 6,237 ============ ============ 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 2002 Form 10-Q, the current report on Form 8-K dated April 23, 2002, and the NU 2001 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the second quarter of 2002 and the first six months of 2002 are provided in the table below. Income Statement Variances (Millions of Dollars) 2002 over/(under) 2001 ------------------------------------- Second Six Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $(38) (13)% $(136) (22)% Operating Expenses: Fuel, purchased and net interchange power (30) (17) (148) (35) Other operation (2) (6) (3) (5) Maintenance - - (3) (7) Depreciation (1) (9) (2) (7) Amortization of regulatory assets, net (10) (a) 9 66 Taxes other than income taxes (1) (7) (3) (14) ---- --- ---- --- Total operating expenses (44) (17) (150) (26) ---- --- ---- --- Operating income 6 19 14 25 ---- --- ---- --- Other (loss)/income, net (6) (a) (40) (a) Interest expense, net (1) (5) 5 23 ---- --- ---- --- Income before income tax expense 1 4 (31) (42) Income tax expense 1 17 (14) (48) ---- --- ---- --- Net income $ - (2)% $(17) (39)% ==== === ==== === (a) Percent greater than 100. Comparison of the Second Quarter of 2002 to the Second Quarter of 2001 Operating Revenues Total operating revenues decreased $38 million or 13 percent in the second quarter of 2002 compared with the same period of 2001, primarily due to lower retail revenues ($9 million), lower wholesale revenues from long-term contracts ($21 million) and sales of capacity and energy ($7 million). Retail revenue decreased primarily due to a rate decrease on May 1, 2001 ($2 million) and lower retail sales ($7 million). Retail kilowatt-hour (kWh) sales decreased by 3.7 percent in the second quarter of 2002. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased in 2002, primarily due to lower purchased-power expenses as a result of the lower wholesale sales. Other Operation and Maintenance Other O&M expense decreased $2 million in 2002, primarily due to lower maintenance costs associated with the fossil plants ($3 million). Depreciation Depreciation decreased in 2002, primarily due to the sale of Millstone 3 in 2001. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased in 2002, primarily resulting from restructuring in 2001. Other (Loss)/Income, Net Other (loss)/income, net decreased in 2002, primarily due to a $4 million gain on the disposition of property in 2001. Comparison of the First Six Months of 2002 to the First Six Months of 2001 Operating Revenues Total operating revenues decreased $136 million or 22 percent in the first six months 2002 compared with the same period of 2001, primarily due to lower retail revenue ($45 million), lower wholesale revenues from long-term contracts ($23 million) and sales of capacity and energy ($69 million). Retail revenue decreased primarily due to a rate decrease on May 1, 2001 ($26 million) and lower retail sales ($19 million). Retail kWh sales decreased by 4.8 percent in 2002. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased in 2002, primarily due to lower purchased-power expenses as a result of the lower wholesale sales. Other Operation and Maintenance Other O&M expense decreased ($6 million) in 2002, primarily due to lower maintenance costs for the fossil plants ($4 million) and lower nuclear expense ($2 million). Depreciation Depreciation decreased in 2002, primarily due to the sale of Millstone 3 in 2001. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net increased in 2002, primarily resulting from restructuring in 2001. Other (Loss)/Income, Net Other (loss)/income, net decreased in 2002, primarily due to sale of Millstone 3 in 2001 ($26 million), a gain on the disposition of property in 2001 ($4 million) and lower interest and dividend income in 2002 ($3 million). Interest Expense Interest expense increased in 2002, primarily due to the issuance of rate reduction bonds, subsequent to the first quarter of 2001. Income Tax Expense Income tax expense decreased in 2002, primarily due to the sale of Millstone 3 in 2001. LIQUIDITY PSNH expects its cash position to improve late in the fourth quarter of 2002 when management expects the sale of NAEC's 35.98 percent share of Seabrook to close. Following the sale of North Atlantic Energy Corporation's (NAEC) share of Seabrook, the Seabrook Power Contracts between PSNH and NAEC will be terminated. PSNH will use the proceeds received from NAEC from this contract termination to amortize stranded costs more quickly, repay debt and return additional equity capital to NU. NU's regulated subsidiaries, including PSNH, have a $350 million unsecured revolving credit facility under which a total of $120 million was outstanding as of June 30, 2002. PSNH had $45 million outstanding under this facility as of June 30, 2002. This revolving credit facility expires in November 2002. As a result of NU's improved credit ratings and strong liquidity, management does not anticipate any difficulty renewing this credit arrangement. PSNH's net cash flows provided by operating activities decreased to $65.5 million in the first six months of 2002, compared with $193.8 million during the same period of 2001. Cash flows provided by operating activities decreased primarily due to increased payments made on accounts payable balances in the first six months of 2002. Additionally, cash flows provided by operating activities decreased as a result of a $16.9 million decrease in net income in 2002. These decreases were partially offset by higher net amortization of recoverable energy costs in 2002 as compared to net deferrals in 2001. There were fewer investing and financing activities in the first half of 2002, as compared to the same period of 2001, primarily due to the issuance of rate reduction bonds and the buydown of the Seabrook Power Contracts in 2001. The level of common dividends totaled $24.5 million in the first six months of 2002 and $18 million in the first six months of 2001. Payment of these common dividends, as well as a common share repurchase in the amount of $260 million in 2001, helped to finance NU's share repurchases and common dividend. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Unaudited)
June 30, December 31, 2002 2001 ---------------- ---------------- (Thousands of Dollars) ASSETS ------ Current Assets: Cash................................................. $ 1 $ 599 Receivables, net..................................... 39,652 43,761 Accounts receivable from affiliated companies........ 91 2,208 Unbilled revenues.................................... 9,230 12,746 Fuel, materials and supplies, at average cost........ 1,623 1,457 Prepayments and other................................ 1,499 1,544 ---------------- ---------------- 52,096 62,315 ---------------- ---------------- Property, Plant and Equipment: Electric utility..................................... 579,784 564,857 Less: Accumulated provision for depreciation...... 191,951 186,784 ---------------- ---------------- 387,833 378,073 Construction work in progress........................ 11,379 18,326 ---------------- ---------------- 399,212 396,399 ---------------- ---------------- Deferred Debits and Other Assets: Regulatory assets.................................... 294,075 320,222 Prepaid pension...................................... 60,276 54,226 Other ............................................... 19,272 19,500 ---------------- ---------------- 373,623 393,948 ---------------- ---------------- Total Assets........................................... $ 824,931 $ 852,662 ================ ================ 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, 2002 2001 ---------------- ---------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION ------------------------------ Current Liabilities: Notes payable to banks................................ $ 45,000 $ 50,000 Notes payable to affiliated companies................. 36,400 9,200 Accounts payable...................................... 17,222 34,970 Accounts payable to affiliated companies.............. 1,231 2,982 Accrued taxes......................................... 3,546 3,691 Accrued interest...................................... 2,126 2,201 Other................................................. 11,145 10,127 ---------------- ---------------- 116,670 113,171 ---------------- ---------------- Rate Reduction Bonds.................................... 147,185 152,317 ---------------- ---------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes..................... 231,128 229,893 Accumulated deferred investment tax credits........... 3,830 3,998 Deferred contractual obligations...................... 34,085 37,357 Other................................................. 39,691 64,309 ---------------- ---------------- 308,734 335,557 ---------------- ---------------- Capitalization: Long-Term Debt........................................ 101,599 101,170 ---------------- ---------------- Common Stockholder's Equity: Common stock, $25 par value - authorized 1,072,471 shares; 434,653 shares outstanding in 2002 and 509,696 shares outstanding in 2001........ 10,866 12,742 Capital surplus, paid in............................ 69,808 82,224 Retained earnings................................... 70,012 55,422 Accumulated other comprehensive income.............. 57 59 ---------------- ---------------- Common Stockholder's Equity........................... 150,743 150,447 ---------------- ---------------- Total Capitalization.................................... 252,342 251,617 ---------------- ---------------- Commitments and Contingencies (Note 2) Total Liabilities and Capitalization.................... $ 824,931 $ 852,662 ================ ================ The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Six Months Ended June 30, June 30, ---------------------------------------------- 2002 2001 2002 2001 ---------------------------------------------- (Thousands of Dollars) Operating Revenues................................. $ 87,191 $ 106,866 $ 183,196 $ 250,166 ------------------------------------------------- Operating Expenses: Operation - Fuel, purchased and net interchange power..... 43,383 79,332 93,583 169,451 Other......................................... 14,003 13,352 24,567 32,147 Maintenance...................................... 3,313 2,677 6,231 12,549 Depreciation..................................... 4,434 3,118 7,623 7,551 Amortization of regulatory assets, net........... 8,577 (1,080) 19,076 125,410 Taxes other than income taxes.................... 2,803 3,061 5,743 7,924 Gain on sale of utility plant.................... - - - (123,148) ------------------------------------------------- Total operating expenses................... 76,513 100,460 156,823 231,884 ------------------------------------------------- Operating Income................................... 10,678 6,406 26,373 18,282 Other (Loss)/Income, Net........................... (2,528) 434 (3,084) (690) ------------------------------------------------- Income Before Interest Expense and Income Tax (Benefit)/Expense..................... 8,150 6,840 23,289 17,592 ------------------------------------------------- Interest Expense: Interest on long-term debt....................... 805 712 1,611 3,706 Interest on rate reduction bonds................. 2,417 909 4,866 909 Other interest................................... 199 765 516 2,665 ------------------------------------------------- Interest expense, net......................... 3,421 2,386 6,993 7,280 ------------------------------------------------- Income Before Income Tax (Benefit)/Expense......... 4,729 4,454 16,296 10,312 Income Tax (Benefit)/Expense....................... (10,593) 2,936 (5,916) 5,475 ------------------------------------------------- Net Income......................................... $ 15,322 $ 1,518 $ 22,212 $ 4,837 ================================================= 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, ------------------------------ 2002 2001 ------------ ------------- (Thousands of Dollars) Operating Activities: Net income........................................................ $ 22,212 $ 4,837 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation.................................................... 7,623 7,551 Deferred income taxes and investment tax credits, net........... (18,735) 8,183 Net amortization of recoverable energy costs.................... 172 3,437 Amortization of regulatory assets, net.......................... 19,076 125,410 Gain on sale of utility plant................................... - (123,148) Net other (uses)/sources of cash................................ (7,649) 24,318 Changes in working capital: Receivables and unbilled revenues, net.......................... 9,742 11,645 Fuel, materials and supplies.................................... (166) 15 Accounts payable................................................ (19,499) 22,043 Accrued taxes................................................... (559) (8,228) Other working capital (excludes cash)........................... 1,395 (10,145) ------------ ------------- Net cash flows provided by operating activities..................... 13,612 65,918 ------------ ------------- Investing Activities: Investments in plant: Electric utility plant.......................................... (10,225) (15,315) Nuclear fuel.................................................... - (140) ------------ ------------- Cash flows used for investments in plant.......................... (10,225) (15,455) Investment in NU system Money Pool................................ 27,200 38,100 Investments in nuclear decommissioning trusts..................... - (21,767) Net proceeds from the sale of utility plant....................... - 177,821 Buyout of IPP contract............................................ - (99,700) Other investment activities, net.................................. 959 1,873 ------------ ------------- Net cash flows provided by investing activities..................... 17,934 80,872 ------------ ------------- Financing Activities: Repurchase of common shares....................................... (13,999) (15,000) Issuance of rate reduction bonds.................................. - 155,000 Retirement of rate reduction bonds................................ (5,132) - Net decrease in short-term debt................................... (5,000) (110,000) Reacquisitions and retirements of long-term debt.................. - (100,000) Reacquisitions and retirements of preferred stock................. - (36,500) Retirement of capital lease obligation......................... - (34,200) Cash dividends on preferred stock................................. - (1,076) Cash dividends on common stock.................................... (8,002) (5,998) Other financing activities, net................................... (11) - ------------ ------------- Net cash flows used in financing activities......................... (32,144) (147,774) ------------ ------------- Net decrease in cash................................................ (598) (984) Cash - beginning of period.......................................... 599 985 ------------ ------------- 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 2002 Form 10-Q, and the NU 2001 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the second quarter of 2002 and the first six months of 2002 are provided in the table below. Income Statement Variances (Millions of Dollars) 2002 over/(under) 2001 ------------------------------------- Second Six Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $ (20) (18)% $ (67) (27)% Operating Expenses: Fuel, purchased and net interchange power (36) (45) (76) (45) Other operation - 5 (8) (24) Maintenance 1 24 (6) (50) Depreciation 1 42 - - Amortization 10 (a) (106) (85) Taxes other than income taxes - (8) (2) (28) Gain on sale of utility plant - - 123 100 ---- --- ---- --- Total operating expenses (24) (24) (75) (32) ---- --- ---- --- Operating income 4 67 8 44 ---- --- ---- --- Other (loss)/income, net (3) (a) (2) (a) Interest expense, net 1 (43) - (4) ---- --- ---- --- Income before income tax expense - 6 6 58 Income tax expense (13) (a) (11) (a) ---- --- ---- --- Net income $ 13 (a)% $ 17 (a)% ==== === ==== === (a) Percent greater than 100. Comparison of the Second Quarter of 2002 to the Second Quarter of 2001 Operating Revenues Operating revenues decreased by $20 million or 18 percent in 2002, primarily due to lower retail revenues ($13 million) and lower wholesale and other revenues ($6 million). Retail revenues were lower primarily due to a decrease in the standard offer service rate ($26 million) partially offset by an increase in the transition charge rate ($8 million) and higher distribution revenues from higher sales. Wholesale revenues were lower primarily due to lower sales of energy and capacity ($4 million). Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased in 2002, primarily due to the lower supply price for standard offer service ($29 million) and the buydown and buyout of various cogeneration contracts ($5 million). Amortization of Regulatory Assets, Net Amortization of regulatory assets, net increased in the second quarter of 2002 due to higher amortizations related to restructuring ($10 million). Other (Loss)/Income, Net Other (loss)/income, net decreased in 2002, primarily due to the DTE's order in the second quarter of 2002 resulting in an adjustment to the gain from the sale of the fossil units in 1999 ($3 million). Income Tax Expense Income tax expense decreased in 2002 primarily due to the recognition in 2002 of investment tax credits as a result of a regulatory decision ($13 million). Comparison of the First Six Months of 2002 to the First Six Months of 2001 Operating Revenues Operating revenues decreased by $67 million or 27 percent in 2002, primarily due to lower retail revenues ($36 million) and lower wholesale and other revenues ($31 million). Retail revenues were lower primarily due to a decrease in the standard offer service rate ($55 million) partially offset by an increase in the transition charge rate ($15 million) and higher distribution revenues from price mix differences ($6 million). Wholesale revenues were lower primarily due to lower sales of energy and capacity ($12 million) and lower revenues from the output of the Millstone nuclear units ($14 million). Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased in 2002, primarily due to the lower supply price for standard offer service ($58 million), the buydown and buyout of various cogeneration contracts ($12 million) and lower nuclear fuel expense ($3 million). Other Operation and Maintenance Other O&M expense decreased by $14 million in 2002, primarily due to lower nuclear expenses as a result of the sale of Millstone units at the end of the first quarter in 2001 ($13 million). Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased in 2002 ($106 million) primarily due to higher amortization in 2001 related to the sale of the Millstone units ($123 million) offset by higher amortizations related to restructuring ($17 million). Other (Loss)/Income, Net Other (loss)/income, net decreased in 2002, primarily due to the DTE's order in the second quarter of 2002 resulting in an adjustment to the gain from the sale of the fossil units in 1999 ($3 million). Income Tax Expense Income tax expense decreased in 2002 primarily due to the recognition in 2002 of investment tax credits as a result of a regulatory decision ($13 million). LIQUIDITY NU's regulated subsidiaries, including WMECO, have a $350 million unsecured revolving credit facility under which a total of $120 million was outstanding as of June 30, 2002. WMECO had $45 million outstanding under this facility as of June 30, 2002. This revolving credit facility expires in November 2002. As a result of NU's improved credit ratings and strong liquidity, management does not anticipate any difficulty renewing this credit arrangement. WMECO's net cash flows provided by operating activities decreased to $13.6 million in the first six months of 2002, compared with $65.9 million during the same period of 2001. Cash flows provided by operating activities decreased primarily due to increased payments made on accounts payable balances in the first six months of 2002 and the recognition of tax credits as a result of a regulatory decision received during the second quarter of 2002. These decreases were partially offset by a $17.4 million increase in net income in 2002. There were fewer investing and financing activities in the first half of 2002, as compared to the same period of 2001, primarily due to the sale of the Millstone units, the buyout and buydown of independent power producer contracts and the issuance of rate reduction certificates in 2001. The level of common dividends totaled $8 million in the first six months of 2002 and $6 million in the first six months of 2001. Payment of these common dividends, as well as a common share repurchase in the amount of $14 million in 2002 and $15 million in 2001, helped to finance NU's share repurchases and common dividend. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The quantitative and qualitative disclosures about market risk are set forth in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," herein. PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS 1. Millstone Station - Damage to Fish Population Lawsuits On April 26, 2000, a lawsuit was filed in Hartford Superior Court naming as defendants the Commissioner of the Connecticut Department of Environmental Protection (DEP), Northeast Nuclear Energy Company and Northeast Utilities Service Company (NUSCO). This lawsuit, brought by the Connecticut Coalition Against Millstone, the Long Island Coalition Against Millstone, The Connecticut Green Party, Don't Waste Connecticut and the STAR Foundation, challenged the validity of previously issued DEP emergency and temporary authorizations allowing Millstone to discharge wastewater not expressly authorized by the facility's water discharge National Pollutant Discharge Elimination System permit. On October 16, 2000, this matter was dismissed by the Superior Court. The plaintiffs filed an appeal of the dismissal with the Connecticut Appellate Court. On June 26, 2002, the Appellate Court granted NUSCO's motion to dismiss the appeal as moot. 2. Consolidated Edison, Inc./NU - Merger Appeals and Related Litigation On March 5, 2001, Consolidated Edison, Inc. (Con Edison) advised NU that it was unwilling to close its merger with NU on the terms set forth in the parties' October 13, 1999 Agreement and Plan of Merger, as amended and restated as of January 11, 2000 (the Merger Agreement). That same day, NU notified Con Edison that it would treat Con Edison's refusal to proceed with the merger as a repudiation and breach of the Merger Agreement and would file suit to obtain the benefits of the transaction for NU shareholders. On March 6, 2001, Con Edison filed suit in the United States District Court for the Southern District of New York (the District Court) seeking a declaratory judgment that it had been relieved of its obligation to proceed with the merger due to, among other things, NU's alleged breach of the Merger Agreement and the alleged occurrence of a "Material Adverse Change" with respect to NU as that term is defined in the Merger Agreement. On March 12, 2001, NU filed suit against Con Edison in the District Court seeking damages in excess of $1 billion arising from Con Edison's breach of the Merger Agreement. On May 11, 2001, in accordance with a stipulation of the parties and order of the District Court, Con Edison filed an amended complaint in which it added claims seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation. Although Con Edison has not in NU's view clearly quantified its damages claim, NU believes that Con Edison's claim is in excess of $600 million. NU disputes both Con Edison's entitlement to any damages as well as its method of computing its alleged damages. On June 1, 2001, NU answered Con Edison's amended complaint, denying all of its material allegations and asserting affirmative defenses, and asserted a counterclaim seeking damages in excess of $1 billion against Con Edison for breach of the Merger Agreement. NU subsequently dismissed its March 12 complaint as duplicative of the June 1 counterclaim. On June 8, 2001, Con Edison answered NU's counterclaim, denying its material allegations and asserting affirmative defenses. The companies have completed discovery in the litigation and have filed motions for summary judgment, which are pending before the District Court. No trial date has been set. Management can predict neither the outcome of this matter nor its ultimate effect on NU. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS NU. At the Annual Meeting of Shareholders of NU held on May 14, 2002, 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 107,371,532 1,816,801 109,188,333 2. Cotton M. Cleveland 107,708,984 1,479,349 109,188,333 3. Sanford Cloud, Jr. 107,765,796 1,422,537 109,188,333 4. James F. Cordes 107,835,239 1,353,094 109,188,333 5. E. Gail de Planque 107,363,247 1,825,086 109,188,333 6. John H. Forsgren 107,781,499 1,406,834 109,188,333 7. Raymond L. Golden 107,381,195 1,807,138 109,188,333 8. Elizabeth T. Kennan 107,208,908 1,979,425 109,188,333 9. Michael G. Morris 107,712,564 1,475,769 109,188,333 10. Robert E. Patricelli 107,742,096 1,446,237 109,188,333 11. John F. Swope 107,275,068 1,913,265 109,188,333 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 2002. The vote ratifying such selection was 104,920,932 votes in favor and 3,556,246 votes against, with 711,155 abstentions and broker nonvotes. CL&P. In a written Consent in Lieu of an Annual Meeting of Stockholders of CL&P (Consent) dated June 19, 2002, stockholders voted to fix the number of directors for the ensuing year at three. The vote fixing the number of directors at three was 7,584,884 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 7,584,884 shares in favor, to serve on the Board of Directors for the ensuing year: David H. Boguslawski, Cheryl W. Grise, and Leon J. Olivier. WMECO. In a written Consent in Lieu of an Annual Meeting of Stockholders of WMECO (Consent) dated June 20, 2002, stockholders voted to fix the number of directors for the ensuing year at eight. The vote fixing the number of directors at eight was 509,696 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of WMECO. Through the Consent the following eight directors were elected, each by a vote of 509,696 shares in favor, to serve on the Board of Directors for the ensuing year: David H. Boguslawski, James E. Byrne, John H. Forsgren, Cheryl W. Grise, Kerry J. Kuhlman, Paul J. McDonald, Michael G. Morris, and Melinda M. Phelps. PSNH. At the Annual Meeting of Stockholders of PSNH held on May 20, 2002, stockholders voted to fix the number of directors for the ensuing year at eight. The vote fixing the number of directors at eight was 388 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of PSNH. At the Annual Meeting, the following eight directors were elected, each by a vote of 388 shares in favor, to serve on the Board of Directors for the ensuing year: David H. Boguslawski, John C. Collins, John H. Forsgren, Cheryl W. Grise, Gerald Letendre, Gary A. Long, Michael G. Morris, and Jane E. Newman. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Listing of Exhibits (NU) Exhibit No. Description ----------- ----------- 10.64 Employment Agreement, by and between Charles W. Shivery and Northeast Utilities Service Company, dated as of June 1, 2002 15 Deloitte & Touche LLP Letter Regarding Unaudited Financial Information 15.1 Arthur Andersen LLP Letter Regarding Unaudited Financial Information 99.1 Certification of Michael G. Morris, Chairman, President and Chief Executive Officer of Northeast Utilities and John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S. C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 7, 2002 (a) Listing of Exhibits (CL&P) 99.1 Certification of Cheryl W. Grise, President Utility Group of Northeast Utilities Service Company, as Agent for The Connecticut Light and Power Company (the Company) and John H. Forsgren, Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company, as Agent for the Company, pursuant to 18 U.S. C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 7, 2002 (a) Listing of Exhibits (PSNH) 99.1 Certification of Michael G. Morris, Chairman and Chief Executive Officer of Public Service Company of New Hampshire and John H. Forsgren, Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company, as Agent for the Company, pursuant to 18 U.S. C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 7, 2002 (a) Listing of Exhibits (WMECO) 99.1 Certification of Michael G. Morris, Chairman and Chief Executive Officer of Western Massachusetts Electric Company and John H. Forsgren, Executive Vice President and Chief Financial Officer of Northeast Utilities Service Company, as Agent for the Company, pursuant to 18 U.S. C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated August 7, 2002 (b) Reports on Form 8-K: NU and PSNH filed current reports on Form 8-K dated April 23, 2002, disclosing: o NU's earnings press release for the first quarter of 2002 and the announcement of the proposed sale of the Seabrook nuclear unit. NU and CL&P filed current reports on Form 8-K dated June 17, 2002, disclosing: o NU's lowering of its earnings estimates for 2002 and CL&P's criticism of the DPUC's decision on standard offer generation rates. NU filed a current report on Form 8-K dated July 23, 2002, disclosing: o NU's earnings press release for the second quarter and six months ended June 30, 2002. NU filed a current report on Form 8-K dated August 2, 2002, disclosing: o NU's submission to the Securities and Exchange Commission (SEC) of Statements under Oath of the Principal Executive Officer and Principal Financial Officer in accordance with the SEC's June 27, 2002 Order requiring the filing of sworn statements pursuant to Section 21(a)(1) of the Securities and Exchange Act of 1934. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. NORTHEAST UTILITIES ------------------- Registrant Date: August 7, 2002 By /s/ John H. Forsgren -------------- -------------------------------------- John H. Forsgren Vice Chairman, Executive Vice President and Chief Financial Officer Date: August 7, 2002 By /s/ John P. Stack -------------- -------------------------------------- John P. Stack Vice President Accounting and Controller SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. THE CONNECTICUT LIGHT AND POWER COMPANY --------------------------------------- Registrant Date: August 7, 2002 By /s/ Randy A. Shoop -------------- -------------------------------------- Randy A. Shoop Treasurer Date: August 7, 2002 By /s/ John P. Stack -------------- -------------------------------------- John P. Stack Vice President - Accounting and Controller SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE --------------------------------------- Registrant Date: August 7, 2002 By /s/ David R. McHale -------------- -------------------------------------- David R. McHale Vice President and Treasurer Date: August 7, 2002 By /s/ John P. Stack -------------- -------------------------------------- John P. Stack Vice President - Accounting and Controller SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. WESTERN MASSACHUSETTS ELECTRIC COMPANY -------------------------------------- Registrant Date: August 7, 2002 By /s/ David R. McHale -------------- -------------------------------------- David R. McHale Vice President and Treasurer Date: August 7, 2002 By /s/ John P. Stack -------------- -------------------------------------- John P. Stack Vice President - Accounting and Controller