-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Mzf5nO+YDThs+kf4Jsx182HJxLU/Ejxxh1gyLElur6E9r0ocU20v74VwX3Xbvtr7 mkTbSQUEE1SP/oSRDgae9w== 0000072741-03-000178.txt : 20031107 0000072741-03-000178.hdr.sgml : 20031107 20031107153325 ACCESSION NUMBER: 0000072741-03-000178 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 16 CONFORMED PERIOD OF REPORT: 20030930 FILED AS OF DATE: 20031107 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONNECTICUT LIGHT & POWER CO CENTRAL INDEX KEY: 0000023426 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 060303850 STATE OF INCORPORATION: CT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 000-00404 FILM NUMBER: 03985057 BUSINESS ADDRESS: STREET 1: SELDEN STREET CITY: BERLIN STATE: CT ZIP: 06037-1616 BUSINESS PHONE: 8606655000 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PUBLIC SERVICE CO OF NEW HAMPSHIRE CENTRAL INDEX KEY: 0000315256 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 020181050 STATE OF INCORPORATION: NH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-06392 FILM NUMBER: 03985056 BUSINESS ADDRESS: STREET 1: 1000 ELM ST CITY: MANCHESTER STATE: NH ZIP: 03105 BUSINESS PHONE: 6036694000 MAIL ADDRESS: STREET 1: 1000 ELM STREET CITY: MANCHESTER STATE: NH ZIP: 03105 FILER: COMPANY DATA: COMPANY CONFORMED NAME: WESTERN MASSACHUSETTS ELECTRIC CO CENTRAL INDEX KEY: 0000106170 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041961130 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 000-07624 FILM NUMBER: 03985054 BUSINESS ADDRESS: STREET 1: 174 BRUSH HILL AVE CITY: WEST SPRINGFIELD STATE: MA ZIP: 01089 BUSINESS PHONE: 4137855871 MAIL ADDRESS: STREET 1: 107 SELDON ST CITY: BERLIN STATE: CT ZIP: 06037-1616 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHEAST UTILITIES SYSTEM CENTRAL INDEX KEY: 0000072741 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 042147929 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-05324 FILM NUMBER: 03985053 BUSINESS ADDRESS: STREET 1: 174 BRUSH HILL AVE CITY: WEST SPRINGFIELD STATE: MA ZIP: 01090-0010 BUSINESS PHONE: 4137855871 MAIL ADDRESS: STREET 1: 107 SELDEN ST CITY: BERLIN STATE: CT ZIP: 06037-1616 10-Q 1 sept10q.txt FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2003 ------------------ OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ________ to ________ Commission Registrant; State of Incorporation; I.R.S. Employer File Number Address; and Telephone Number Identification No. - ----------- ----------------------------------- ------------------ 1-5324 NORTHEAST UTILITIES 04-2147929 ------------------- (a Massachusetts voluntary association) 174 Brush Hill Avenue West Springfield, Massachusetts 01090-2010 Telephone: (413) 785-5871 0-11419 THE CONNECTICUT LIGHT AND POWER COMPANY 06-0303850 --------------------------------------- (a Connecticut corporation) 107 Selden Street Berlin, Connecticut 06037-1616 Telephone: (860) 665-5000 1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 02-0181050 --------------------------------------- (a New Hampshire corporation) Energy Park 780 North Commercial Street Manchester, New Hampshire 03101-1134 Telephone: (603) 669-4000 0-7624 WESTERN MASSACHUSETTS ELECTRIC COMPANY 04-1961130 -------------------------------------- (a Massachusetts corporation) 174 Brush Hill Avenue West Springfield, Massachusetts 01090-2010 Telephone: (413) 785-5871 Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark whether the registrants are accelerated filers (as defined in Rule 12b-2 of the Exchange Act): Yes X No --- --- Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of the latest practicable date: Company - Class of Stock Outstanding at October 31, 2003 - ------------------------ ------------------------------- Northeast Utilities Common shares, $5.00 par value 127,369,219 shares The Connecticut Light and Power Company Common stock, $10.00 par value 6,035,205 shares Public Service Company of New Hampshire Common stock, $1.00 par value 301 shares Western Massachusetts Electric Company Common stock, $25.00 par value 434,653 shares GLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report: NU COMPANIES OR SEGMENTS Boulos....................... E.S. Boulos Company CL&P......................... The Connecticut Light and Power Company CRC.......................... CL&P Receivables Corporation HWP.......................... Holyoke Water Power Company NGC.......................... Northeast Generation Company NGS.......................... Northeast Generation Services Company NU or the company............ Northeast Utilities NU Enterprises............... NU's competitive subsidiaries comprised of Select Energy, NGC, SESI, NGS, HWP, and Woods Network. For further information, see Note 7, "Segment Information," to the consolidated financial statements. PSNH......................... Public Service Company of New Hampshire RMS.......................... R. M. Services, Inc. Select Energy................ Select Energy, Inc. (including its wholly owned subsidiary SENY) SENY......................... Select Energy New York, Inc. SESI......................... Select Energy Services, Inc. Utility Group................ NU's regulated utilities comprised of CL&P, PSNH, WMECO, and Yankee Gas. For further information, see Note 7, "Segment Information," to the consolidated financial statements. WMECO........................ Western Massachusetts Electric Company Woods Network................ Woods Network Services, Inc. Yankee....................... Yankee Energy System, Inc. Yankee Gas................... Yankee Gas Services Company THIRD PARTIES Bechtel...................... Bechtel Power Corporation CVEC......................... Connecticut Valley Electric Company CYAPC........................ Connecticut Yankee Atomic Power Company MGT.......................... Meriden Gas Turbines, LLC NRG.......................... NRG Energy, Inc. NRG-PM....................... NRG Power Marketing, Inc. REGULATORS DPUC......................... Connecticut Department of Public Utility Control DTE.......................... Massachusetts Department of Telecommunications and Energy FERC......................... Federal Energy Regulatory Commission NHPUC........................ New Hampshire Public Utilities Commission SEC.......................... Securities and Exchange Commission OTHER ABO.......................... Accumulated Benefit Obligation Act, the..................... Public Act No. 03-135 C&LM......................... Conservation and Load Management CSC.......................... Connecticut Siting Council CTA.......................... Competitive Transition Assessment DE........................... Delivery Efficiency DIG.......................... Derivative Implementation Group EITF......................... Emerging Issues Task Force EPS.......................... Earnings per Share FASB......................... Financial Accounting Standards Board FIN.......................... FASB Interpretation Fitch........................ Fitch Ratings FMCC......................... Federally Mandated Congestion Costs GSC.......................... Generation Service Charge IERM......................... Infrastructure Expansion Rate Mechanism Incentive Plan............... Northeast Utilities Incentive Plan ISO-NE....................... New England Independent System Operator kWh.......................... Kilowatt-hour LMP.......................... Locational Marginal Pricing MW........................... Megawatts NU 2002 Form 10-K............ The Northeast Utilities and Subsidiaries combined 2002 Form 10-K as filed with the SEC NYMEX........................ New York Mercantile Exchange O&M.......................... Operation and Maintenance Restructuring Settlement................. "Agreement to Settle PSNH Restructuring" RMR.......................... Reliability Must Run SBC.......................... System Benefits Charge SCRC......................... Stranded Cost Recovery Charge SFAS......................... Statement of Financial Accounting Standards SMD.......................... Standard Market Design TSO.......................... Transitional Standard Offer VIE.......................... Variable Interest Entity Northeast Utilities and Subsidiaries The Connecticut Light and Power Company and Subsidiaries Public Service Company of New Hampshire and Subsidiaries Western Massachusetts Electric Company and Subsidiary TABLE OF CONTENTS ----------------- Page ---- Part I. Financial Information Item 1. Consolidated Financial Statements (Unaudited) and Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations For the following companies: Northeast Utilities and Subsidiaries Consolidated Balance Sheets - September 30, 2003 and December 31, 2002............... 2 Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2003 and 2002............................ 4 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2003 and 2002.......... 5 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 6 Independent Accountants' Report............................. 39 Notes to Consolidated Financial Statements (unaudited - all companies).................................. 40 The Connecticut Light and Power Company and Subsidiaries Consolidated Balance Sheets - September 30, 2003 and December 31, 2002............... 68 Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2003 and 2002............................ 70 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2003 and 2002.......... 71 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 72 Public Service Company of New Hampshire and Subsidiaries Consolidated Balance Sheets - September 30, 2003 and December 31, 2002............... 78 Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2003 and 2002............................ 80 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2003 and 2002.......... 81 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 82 Western Massachusetts Electric Company and Subsidiary Consolidated Balance Sheets - September 30, 2003 and December 31, 2002............... 88 Consolidated Statements of Income - Three Months and Nine Months Ended September 30, 2003 and 2002............................ 90 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2003 and 2002.......... 91 Management's Discussion and Analysis of Financial Condition and Results of Operations.......... 92 Item 3. Quantitative and Qualitative Disclosures About Market Risk.......................... 95 Item 4. Controls and Procedures................................ 95 Part II. Other Information Item 1. Legal Proceedings...................................... 96 Item 6. Exhibits and Reports on Form 8-K....................... 99 Signatures............................................................ 102 NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2003 2002 --------------- --------------- (Thousands of Dollars) ASSETS - ------ Current Assets: Cash and cash equivalents $ 118,138 $ 54,678 Restricted cash - LMP costs 45,760 - Special deposits 75,657 43,261 Investments in securitizable assets 215,592 178,908 Receivables, net 637,039 767,089 Unbilled revenues 95,498 126,236 Fuel, materials and supplies, at average cost 160,400 119,853 Derivative assets 103,768 130,929 Prepayments and other 81,556 110,261 --------------- --------------- 1,533,408 1,531,215 --------------- --------------- Property, Plant and Equipment: Electric utility 5,360,649 5,141,951 Gas utility 708,986 679,055 Competitive energy 886,478 866,294 Other 209,040 205,115 --------------- --------------- 7,165,153 6,892,415 Less: Accumulated depreciation 2,564,544 2,484,613 --------------- --------------- 4,600,609 4,407,802 Construction work in progress 374,691 320,567 --------------- --------------- 4,975,300 4,728,369 --------------- --------------- Deferred Debits and Other Assets: Regulatory assets 2,947,670 3,076,095 Goodwill and other purchased intangible assets, net 343,904 345,867 Prepaid pension 352,668 328,890 Other 445,418 433,444 --------------- --------------- 4,089,660 4,184,296 --------------- --------------- Total Assets $ 10,598,368 $ 10,443,880 =============== ===============
The accompanying notes are an integral part of these consolidated financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2003 2002 --------------- --------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION - ------------------------------ Current Liabilities: Notes payable to banks $ 40,000 $ 56,000 Long-term debt - current portion 59,327 56,906 Accounts payable 787,024 776,219 Accrued taxes 68,816 141,667 Accrued interest 57,820 40,597 Derivative liabilities 65,866 63,900 Other 205,501 208,680 ---------------- --------------- 1,284,354 1,343,969 --------------- --------------- Rate Reduction Bonds 1,772,637 1,899,312 --------------- --------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 1,362,713 1,436,507 Accumulated deferred investment tax credits 103,607 106,471 Deferred contractual obligations 321,197 354,469 Other 878,146 689,287 --------------- --------------- 2,665,663 2,586,734 --------------- --------------- Capitalization: Long-Term Debt 2,505,222 2,287,144 --------------- --------------- Preferred Stock - Nonredeemable 116,200 116,200 --------------- --------------- Common Shareholders' Equity: Common shares, $5 par value - authorized 225,000,000 shares; 150,098,023 shares issued and 127,254,402 shares outstanding in 2003 and 149,375,847 shares issued and 127,562,031 shares outstanding in 2002 750,492 746,879 Capital surplus, paid in 1,106,466 1,108,338 Deferred contribution plan - employee stock ownership plan (76,970) (87,746) Retained earnings 837,963 765,611 Accumulated other comprehensive (loss)/income (2,862) 14,927 Treasury stock, 19,518,023 shares in 2003 and 18,022,415 shares in 2002 (360,797) (337,488) --------------- --------------- Common Shareholders' Equity 2,254,292 2,210,521 --------------- --------------- Total Capitalization 4,875,714 4,613,865 --------------- --------------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization $ 10,598,368 $ 10,443,880 =============== ===============
The accompanying notes are an integral part of these consolidated financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, -------------------------------- ------------------------------ 2003 2002 2003 2002 --------------- -------------- -------------- ------------- Operating Revenues $ 2,054,274 $ 1,414,304 $ 5,200,252 $ 3,840,693 ------------- -------------- -------------- -------------- Operating Expenses: Operation - Fuel, purchased and net interchange power 1,445,482 850,757 3,408,712 2,204,434 Other 224,606 184,110 645,156 580,865 Maintenance 55,687 68,271 169,859 194,032 Depreciation 50,879 50,946 151,044 156,757 Amortization 53,995 59,160 132,791 85,114 Amortization of rate reduction bonds 40,729 35,380 115,232 116,016 Taxes other than income taxes 53,169 47,585 178,603 177,043 ------------- -------------- -------------- -------------- Total operating expenses 1,924,547 1,296,209 4,801,397 3,514,261 ------------- -------------- -------------- -------------- Operating Income 129,727 118,095 398,855 326,432 Interest Expense: Interest on long-term debt 32,010 34,137 93,496 101,500 Interest on rate reduction bonds 26,863 28,751 82,088 87,539 Other interest 4,474 4,825 10,835 14,569 ------------- -------------- -------------- -------------- Interest expense, net 63,347 67,713 186,419 203,608 ------------- -------------- -------------- -------------- Other Income, Net 4,678 32,059 6,008 19,715 ------------- -------------- -------------- -------------- Income Before Income Tax Expense 71,058 82,441 218,444 142,539 Income Tax Expense 25,689 32,476 83,223 42,296 ------------- -------------- -------------- -------------- Income Before Preferred Dividends of Subsidiaries 45,369 49,965 135,221 100,243 Preferred Dividends of Subsidiaries 1,390 1,390 4,169 4,169 ------------- -------------- -------------- -------------- Income Before Cumulative Effect of Accounting Change 43,979 48,575 131,052 96,074 Cumulative effect of accounting change, net of tax benefit of $2,553 (4,741) - (4,741) - ------------- -------------- -------------- -------------- Net Income $ 39,238 $ 48,575 $ 126,311 $ 96,074 ============= ============== ============== ============== Basic and Fully Diluted Earnings Per Common Share: Income Before Cumulative Effect of Accounting Change $ 0.35 $ 0.38 $ 1.03 $ 0.74 Cumulative effect of accounting change, net of tax benefit (0.04) - (0.04) - ------------- -------------- -------------- -------------- Basic and Fully Diluted Earnings Per Common Share $ 0.31 $ 0.38 $ 0.99 $ 0.74 ============= ============== ============== ============== Basic Common Shares Outstanding (average) 127,167,690 129,344,724 126,976,161 129,508,840 ============= ============== ============== ============== Fully Diluted Common Shares Outstanding (average) 127,303,973 129,508,794 127,086,417 129,737,249 ============= ============== ============== ==============
The accompanying notes are an integral part of these consolidated financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, ------------------------------ 2003 2002 ------------- ------------- (Thousands of Dollars) Operating Activities: Income before preferred dividends of subsidiaries $ 135,221 $ 100,243 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation 151,044 156,757 Deferred income taxes and investment tax credits, net (48,815) (54,207) Amortization 132,791 85,114 Amortization of rate reduction bonds 115,232 116,016 (Deferral)/amortization of recoverable energy costs (5,480) 19,557 Prepaid pension (23,778) (55,436) Cumulative effect of an accounting change (4,741) - Regulatory recoveries 117,138 48,915 Other sources of cash 14,911 73,241 Other uses of cash (122,284) (57,044) Changes in current assets and liabilities: Restricted cash - LMP costs (45,760) - Receivables and unbilled revenues, net 160,789 29,223 Fuel, materials and supplies (40,548) (23,285) Accounts payable 10,805 (52,846) Accrued taxes (72,851) 23,754 Investments in securitizable assets (36,684) 49,570 Other current assets and liabilities (excludes cash) 25,686 12,678 ---------- ---------- Net cash flows provided by operating activities 462,676 472,250 ---------- ---------- Investing Activities: Investments in plant: Electric, gas and other utility plant (372,854) (308,757) Competitive energy assets (13,144) (18,128) Nuclear fuel - (434) ---------- ---------- Cash flows used for investments in plant (385,998) (327,319) Buyout/buydown of IPP contracts (20,437) (5,152) Payment for acquisitions, net of cash acquired - (15,300) Other investment activities, net 8,777 6,957 ---------- ---------- Net cash flows used in investing activities (397,658) (340,814) ---------- ---------- Financing Activities: Issuance of common shares 9,940 7,445 Repurchase of common shares (23,209) (30,136) Issuance of long-term debt 250,384 263,000 Issuance of rate reduction bonds - 50,000 Retirement of rate reduction bonds (126,374) (132,883) Net (decrease)/increase in short-term debt (16,000) 25,233 Reacquisitions and retirements of long-term debt (33,607) (285,146) Cash dividends on preferred stock (4,169) (4,169) Cash dividends on common shares (53,959) (50,164) Other financing activities, net (4,564) (548) ---------- ---------- Net cash flows used in financing activities (1,558) (157,368) ---------- ---------- Net increase/(decrease) in cash and cash equivalents 63,460 (25,932) Cash and cash equivalents - beginning of period 54,678 96,658 ---------- ---------- Cash and cash equivalents - end of period $ 118,138 $ 70,726 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Management's Discussion and Analysis of Financial Condition and Results of Operations This discussion should be read in conjunction with the consolidated financial statements and footnotes in this Form 10-Q, the first and second quarter 2003 reports on Form 10-Q and the NU 2002 Form 10-K. FINANCIAL CONDITION Overview - -------- Consolidated: Northeast Utilities (NU or the company) earned $44 million, or $0.35 per share in the third quarter of 2003, before the cumulative effect of accounting change, compared with $48.6 million, or $0.38 per share, in the third quarter of 2002. After the cumulative effect of an accounting change, NU earned $39.2 million, or $0.31 a share, in the third quarter of 2003. Third quarter 2003 results included a negative $4.7 million after-tax cumulative effect of accounting change as a result of the adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities," related to the consolidation of R. M. Services, Inc. (RMS), a bill collection company that was once a subsidiary of Yankee Energy System, Inc. (Yankee). NU merged with Yankee in March 2000 and sold RMS in June 2001, retaining a preferred equity interest. In connection with the adoption of FIN 46, effective July 1, 2003, NU was required to consolidate RMS into NU's financial statements and adjusted its equity interest as a cumulative effect of an accounting change. Third quarter 2002 results included a net after-tax gain of $14.5 million, or $0.11 per share, related to the elimination of certain reserves associated with NU's ownership share of the Seabrook nuclear unit (Seabrook). NU sold its 40.04 percent ownership share of Seabrook in November 2002. For the first nine months of 2003, NU earned $126.3 million after the cumulative effect of the accounting change, or $0.99 per share, compared with net income of $96.1 million, or $0.74 per share, for the first nine months of 2002. The results for the first nine months of 2002 included elimination of the aforementioned Seabrook reserves, as well as after-tax write-downs totaling $10 million, or $0.08 per share, related to NU's investments in NEON Communications, Inc. (NEON) and Acumentrics Corporation (Acumentrics) and approximately $13 million, or $0.10 per share, of investment tax credits related to divested generation reflected by Western Massachusetts Electric Company (WMECO) as a result of a regulatory decision. The results for the first nine months of 2003 did not include any similar write-downs or investment tax credits. All per share amounts are reported on a fully diluted basis. Third quarter results benefited from improved results at NU Enterprises, lower regulated company controllable operation and maintenance costs, and lower interest costs. Those factors were offset by lower pension income and the absence of earnings related to Seabrook. Net income for NU Enterprises for the first nine months of 2003 was $24 million, or a $62.7 million increase in net income, compared to a loss of $38.7 million for the first nine months of 2002. Net income for the first nine months of 2003 for the Utility Group was $111 million, or a $47.5 million decrease from 2002 net income of $158.5 million. The reduction in Utility Group net income was the result of the absence of approximately $13 million of investment tax credits that were reflected in the second quarter of 2002 at WMECO, as well as lower pension income and the loss of net income related to Seabrook in 2003 as compared to 2002. NU's earnings per share also benefited modestly from its share repurchase program. NU repurchased approximately 1.6 million shares at an average price of $14.14 in the first quarter of 2003. There have been no further share repurchases in the second or third quarters of 2003. NU had approximately 127 million shares outstanding at September 30, 2003. NU's revenues during the first nine months of 2003 increased to $5.2 billion from $3.8 billion in the same period of 2002, or an increase of $1.4 billion. Of the $1.4 billion increase in NU's revenues, $1.1 billion related to NU Enterprises. NU Enterprises' wholesale revenues increased primarily due to $400 million in higher requirements sales and $600 million in higher short- term and non-requirements sales. A contributing factor to the higher short- term sales is the change in settlement methodology at the New England Independent System Operator (ISO-NE) as a result of the implementation of Standard Market Design (SMD). The increase in revenues is also due to increases in electric and firm natural gas sales at the Utility Group in 2003 as compared to 2002. Utility Group: Utility Group net income was lower due to the absence of approximately $13 million of investment tax credits that were reflected in the second quarter of 2002 at WMECO, as well as lower pension income and the loss of net income related to Seabrook. Lower pension income and the lack of Seabrook earnings resulted in approximately a $13 million and a $9 million decrease, respectively, in net income in 2003 as compared to 2002. As a result of adjustments to estimated unbilled electric revenues, third quarter 2003 Utility Group retail electric sales increased 4.9 percent in the third quarter of 2003 compared to 2002. Absent that adjustment, Utility Group retail electric sales would have decreased 0.3 percent. An adjustment to estimated unbilled revenues had a negative impact on Yankee Gas Services Company (Yankee Gas). Combined, the adjustments to estimated unbilled revenues increased NU's net income by approximately $5.7 million in the third quarter of 2003, resulting from a process to validate and update the assumptions used to estimate unbilled revenues. For further information regarding unbilled revenues, see "Critical Accounting Policies and Estimates Updates - Adjustments to Estimates of Unbilled Revenues," included in this Management's Discussion and Analysis. Earnings before preferred dividends at The Connecticut Light and Power Company (CL&P) totaled $30.4 million in the third quarter of 2003 and $63.2 million in the first nine months of 2003, compared to $29.3 million in the third quarter of 2002 and $62.4 million in the first nine months of 2002. Earnings for the three and nine months ended September 30, 2003 were negatively impacted by lower pension income and lower earnings on a reduced level of regulatory assets but were positively impacted by the adjustment to the estimate of unbilled revenues. Public Service Company of New Hampshire (PSNH) earned $12.6 million in the third quarter of 2003 and $34.5 million in the first nine months of 2003, compared to $19.5 million in the third quarter of 2002 and $46.4 million in the first nine months of 2002. Lower PSNH net income resulted from higher pension expense and a lower level of regulatory assets earning a return, primarily due to the sale of Seabrook. These decreases were offset by an increase to revenues as a result of an adjustment to the estimate of unbilled revenues. The reduction in the level of net regulatory assets will continue to negatively affect PSNH's 2003 to 2002 net income comparisons. Additionally, net income for the first nine months of 2002 includes $4.2 million related to the positive resolution of certain contingencies related to a PSNH regulatory proceeding. Net income at WMECO was $5.2 million in the third quarter of 2003 and $13.9 million in the first nine months of 2003, compared to $4.7 million in the third quarter of 2002 and $26.9 million in the first nine months of 2002. The net income decrease in year to date 2003 earnings was due primarily to the recognition of $13 million in investment tax credits in the second quarter of 2002 as a result of a regulatory decision. Yankee Gas lost $9.6 million in the third quarter of 2003 and earned $3.4 million in the first nine months of 2003, compared to a loss of $5.8 million in the third quarter of 2002 and net income of $6.2 million in the first nine months of 2002. Lower Yankee Gas earnings are primarily due to lower revenues in the third quarter as a result of a downward adjustment in estimated unbilled revenues offset by the positive impact of colder temperatures in 2003 compared to 2002. NU expects that pension income will decline from approximately $73 million in 2002 to approximately $32 million in 2003. Of the $41 million decline, approximately 70 percent ($29 million) will reduce pre-tax earnings. The remaining 30 percent ($12 million) relates to employees working on capital projects and will be reflected as capital expenditures. The $29 million increase in operating expenses is reflected evenly throughout the year and has resulted in a decline of approximately $4.4 million in net income per quarter during 2003. NU Enterprises: NU Enterprises, Inc. is the parent company of Select Energy, Inc. (Select Energy), Northeast Generation Company (NGC), Select Energy Services, Inc. (SESI), Northeast Generation Services Company (NGS), and their respective subsidiaries, and Woods Network Services, Inc. (Woods Network), all of which are collectively referred to as "NU Enterprises." The ongoing generation operations of Holyoke Water Power Company (HWP) are also included in the results of NU Enterprises. NU Enterprises earned $6.9 million in the third quarter of 2003 and $24 million in the first nine months of 2003, compared to a loss of $9 million in the third quarter of 2002 and a loss of $38.7 million in the first nine months of 2002. NU Enterprises' net income improved due to better margins on wholesale and retail contracts, better performance at NGC, which owns nearly 1,300 megawatts (MW) of primarily hydroelectric and pumped storage generating capacity in Massachusetts and Connecticut, and the absence of natural gas trading positions in 2003. Natural gas trading positions in the first half of 2002 resulted in trading losses. Over the past year, Select Energy has significantly reduced its trading activities. Select Energy's merchant energy business includes a wholesale business and a retail marketing business. The wholesale business includes wholesale origination, portfolio management and the operation of more than 1,400 MW of pumped storage, hydroelectric and coal-fired generation assets. The wholesale business earned $4.5 million in the third quarter of 2003 and $23.9 million in the first nine months of 2003, compared to losses of $2.4 million in the third quarter of 2002 and $13.6 million in the first nine months of 2002. The wholesale business benefited from a return to normal precipitation in western New England during the first nine months of 2003, compared with the same period of 2002, which increased conventional hydroelectric output. This increase in output resulted in $3.7 million of additional net income in 2003, as compared to 2002. The wholesale business also benefited from the absence of natural gas trading losses in 2003. The retail marketing business lost $1.6 million in the first nine months of 2003 compared to a loss of $26.3 million in the first nine months of 2002. The 2003 improved retail results are primarily due to improved margins and growth in retail electric sales along with improved management of gas retail contracts. The energy services businesses earned $0.2 million in the third quarter of 2003 and $2.1 million in the first nine months of 2003 compared to earnings of $1.7 million in the third quarter of 2002 and $1.8 million in the first nine months of 2002. NU Enterprises parent costs totaled $0.2 million in the third quarter of 2003 and $0.4 million in the first nine months of 2003 compared to $0.2 million in the third quarter of 2002 and $0.6 million in the first nine months of 2002. Future Outlook - -------------- Consolidated: NU has narrowed its forecasted earnings in 2003 to between $1.20 per share and $1.30 per share from its previous forecast of between $1.10 per share and $1.30 per share. That range excludes any potential losses at Select Energy due to the ongoing dispute over locational marginal pricing (LMP) costs, which are estimated to be $90 million. NU also has established a forecasted earnings range of between $1.20 per share and $1.40 per share for 2004. Utility Group: The forecasted earnings in 2003 reflect earnings of between $1.10 per share and $1.15 per share at the Utility Group. The NU consolidated earnings range of between $1.20 per share and $1.40 per share for 2004 reflects earnings of between $1.08 and $1.20 per share at the Utility Group. The 2004 Utility Group earnings range is dependent on a number of factors, including the outcome of state rate cases involving CL&P and PSNH and a Federal Energy Regulatory Commission (FERC) rate case involving NU's transmission tariffs. A final decision from the Connecticut Department of Public Utility Control (DPUC) in CL&P's rate case is due on December 15, 2003 with new rates effective on January 1, 2004. The filing of a PSNH rate case is expected by the end of this year with new rates effective on February 1, 2004. On October 22, 2003, the FERC preliminarily approved NU's requested transmission tariff, allowing rates to go into effect on October 28, 2003, subject to refund. This new formula tariff will provide NU with more timely recovery of the costs associated with its transmission capital program. NU Enterprises: The forecasted earnings in 2003 reflect earnings of between $0.20 per share and $0.25 per share at NU Enterprises. The NU consolidated earnings range of between $1.20 per share and $1.40 per share for 2004 reflects earnings of between $0.22 and $0.30 per share at NU Enterprises. The 2003 NU Enterprises earnings range excludes any potential negative impact on Select Energy from an ongoing LMP dispute involving Select Energy's contract to provide CL&P with 50 percent of its standard offer service through the end of 2003. The LMP dispute, now before an administrative law judge at the FERC, relates to whether CL&P's standard offer suppliers, including Select Energy, or CL&P's retail customers are responsible for incremental costs associated with the implementation of SMD and LMP beginning in March 2003. Select Energy's portion of these costs is $90 million. A FERC decision is expected in 2004. For further information regarding the LMP dispute, see "Impacts of Standard Market Design," in this Management's Discussion and Analysis. The 2004 earnings range of between $0.22 per share and $0.30 per share represents earnings of between $28 million and $38 million. Management estimates that between $24 million and $31 million of those earnings in 2004 will come from the wholesale and retail merchant energy business and between $4 million and $7 million from the energy services business. Those ranges are heavily dependent on NU Enterprises' ability to achieve targeted wholesale and retail origination margins, successfully manage its contract portfolios and achieve targeted growth in the services business. Other: NU continues to project parent company debt and other expenses of approximately $0.10 per share in 2003. The 2004 earnings range also reflects $0.10 per share of parent company after-tax expenses, primarily related to interest expense. Liquidity - --------- Consolidated: NU's liquidity continues to be strong as NU had $118.1 million of cash and cash equivalents on hand at September 30, 2003. NU's net cash flows from operating activities decreased to $462.7 million in the first nine months of 2003 from $472.3 million in the first nine months of 2002. The decrease in cash flows from operating activities resulted from the payment of $193 million of taxes, primarily on the gain on the sale of Seabrook, increases in other uses of cash, which relate primarily to other regulatory assets and increases in restricted cash, due to the placing of incremental LMP costs collected into an escrow account beginning in July 2003. These decreases were partially offset by a $35 million increase in income before preferred dividends of subsidiaries combined with the positive impacts of increased amortization from recovery of regulatory assets, lower pension income, decreases in accounts receivable, and increases in accounts payable. NU's liquidity was also enhanced by recent financings. On June 3, 2003, NU issued $150 million of five-year notes at an interest rate of 3.3 percent. The proceeds from the issuance of these notes were primarily used to refinance Select Energy's short-term debt. On September 30, 2003, WMECO issued $55 million of ten-year 5 percent notes, the proceeds from which WMECO used to repay a similar level of borrowings from the NU system Money Pool. On October 1, 2003, CL&P fixed the interest rate on $62 million of variable- rate tax-exempt borrowings for five years at 3.35 percent. In the first nine months of 2003, NU also repaid $33.6 million of long-term debt and $126.4 million of rate reduction bonds. NU's capital expenditures totaled $386 million in the first nine months of 2003 compared to $327.3 million in the first nine months of 2002. NU currently projects capital expenditures of approximately $600 million in 2003. The level of common dividends totaled $54 million in the first nine months of 2003, compared with $50.2 million in the first nine months of 2002. The increase in the level of common dividends resulted from NU paying two $0.1375 per share quarterly common dividends and one $0.15 per share quarterly common dividend in the first nine months of 2003, compared to two $0.125 per share quarterly common dividends and one $0.1375 per share quarterly common dividend in the first nine months of 2002. On October 14, 2003, the NU Board of Trustees declared a common dividend of $0.15 per share payable on December 31, 2003, to shareholders of record on December 1, 2003. The dividend increase was consistent with management's objective to continue to increase the dividend level annually, subject to NU's ability to meet earnings targets and the judgment of its Board of Trustees at the time the dividends are declared. In the third quarter 2003, Fitch Ratings (Fitch) raised the outlook of NU's and CL&P's credit ratings to stable from negative. The change in outlook is a result of Fitch's belief that the risks associated with CL&P's standard offer service contract with NRG Energy, Inc. (NRG) had declined. For more information on NRG see the "NRG Exposures" section of this Management's Discussion and Analysis and Note 4B, "Commitments and Contingencies - NRG Energy, Inc. Exposures," to the consolidated financial statements. Utility Group: At September 30, 2003, NU's Utility Group had $10 million in borrowings outstanding on its $300 million revolving credit line. This credit line expires on November 11, 2003, and management expects to extend this credit line from November 2003 through November 2004. At September 30, 2003, CL&P had $40 million of accounts receivable and unbilled revenues sold under its arrangement with a financial institution to sell up to $100 million in accounts receivable and unbilled revenues. This arrangement expires in July 2004. For more information regarding CL&P's accounts receivable facility, see Note 1F, "Sale of Customer Receivables," to the consolidated financial statements. CL&P is seeking approval from its preferred shareholders to permanently amend its charter to eliminate a requirement that unsecured debt represent no more than 10 percent of total capitalization. At September 30, 2003, CL&P's unsecured debt represented approximately 3 percent of CL&P's total capitalization. CL&P is offering its preferred holders a payment of 1 percent of the $116.2 million par value of their shares if the preferred holders vote in favor of the amendment and CL&P implements it. Preferred holders of record as of September 30, 2003, are eligible to vote at a special meeting, which will be held on November 25, 2003. Holders of at least two- thirds of CL&P's approximately 2.3 million shares of preferred stock must vote in favor of the change for it to pass. Management believes that CL&P will benefit from such a change due to increased financial flexibility. In the event that this change fails or if CL&P chooses not to implement it, CL&P is also asking preferred holders to endorse another 10-year waiver that would allow CL&P's unsecured debt to rise to 20 percent of total capitalization. CL&P preferred holders approved a similar waiver in 1993 that is scheduled to expire in March 2004. Prior to July 1, 2003, CL&P recovered approximately $30 million of incremental LMP costs from its customers and has withheld payment of these incremental LMP costs from its standard offer service suppliers. This positively impacted CL&P's liquidity. In July 2003, CL&P began depositing new recoveries into an escrow account. Accordingly, further recovery of these costs did not impact CL&P's liquidity. When the LMP dispute is resolved, there will be a negative impact on CL&P's liquidity for the amounts recovered but not deposited into the escrow account, as these amounts are paid to standard offer service suppliers or returned to customers. NU Enterprises: NU Enterprises had $30 million in borrowings and $123.2 million in letters of credit outstanding on NU parent's $350 million revolving credit line. This credit line expires on November 11, 2003, and management expects to extend this credit line from November 2003 through November 2004. At September 30, 2003, Select Energy has incurred and billed CL&P for incremental LMP costs in the amount of approximately $71 million. As a result of the LMP dispute, Select Energy has not received any amounts from CL&P, which has negatively impacted Select Energy's liquidity. This negative impact is expected to continue to increase until the resolution of the LMP dispute. Impacts of Standard Market Design - --------------------------------- Consolidated: On March 1, 2003, ISO-NE implemented SMD. As part of SMD, LMP is now utilized to assign value and causation to transmission congestion and line losses. Transmission congestion costs represent the additional costs incurred due to the need to run uneconomic generating units in certain areas that have transmission constraints, which prevent these areas from obtaining alternative lower-cost generation. Line losses represent losses of electricity as it is sent over transmission lines. The costs associated with transmission congestion and line losses are now assigned to the pricing zone in which they occur and the calculation of line losses is now based on an economic formula. Prior to March 1, 2003, those costs were spread across virtually all New England electric customers based on engineering data of actual line losses experienced. As part of the implementation of SMD, ISO-NE established eight separate pricing zones in New England: three in Massachusetts and one in each of the five other New England states. The three components of the LMP for each zone are 1) an energy cost, 2) congestion costs and 3) line loss charges assigned to the zone. LMP is increasing costs in zones that have inadequate or less cost-efficient generation and/or transmission constraints, such as Connecticut, and decreasing costs in zones that have sufficient or excess generation, such as Maine. The implementation of SMD has also impacted pricing under wholesale energy contracts depending on the energy delivery points chosen under those contracts. Utility Group: Connecticut has been designated a single pricing zone by ISO- NE. For the seven-month period from March 1, 2003 through September 30, 2003, incremental LMP costs have totaled approximately $132.5 million, including $71 million related to Select Energy. Approximately 70 percent of these incremental costs (approximately $90 million, or approximately $13 million per month on average) were associated with line losses, with monthly line losses ranging from $9.5 million to $17 million. LMP costs also include approximately $41 million related to congestion costs for the seven-month period with monthly congestion costs ranging from $0.2 million to $16.5 million. In October 2003, incremental LMP costs amounted to approximately $13.7 million, including $8.6 million of line loss charges and $5.2 million of congestion costs. Management currently estimates that total incremental LMP costs for CL&P for 2003 will be approximately $180 million (approximately $120 million in line losses and approximately $60 million in congestion costs). Actual incremental LMP costs could be higher if congestion and line loss charges are greater than anticipated as a result of unusual weather and other factors management cannot predict. CL&P's standard offer service contracts were executed in the fall of 1999 with the delivery points in the contracts at the suppliers' choice at any point on the New England power pool. Prior to March 1, 2003, delivery by the suppliers anywhere on the New England power pool resulted in the suppliers being charged and paying their respective share of socialized congestion costs. Subsequent to March 1, 2003, the delivery points chosen by the suppliers have been zones with no or negative congestion and/or line losses. Management believes that under the legal interpretation of the terms of its standard offer service contracts with its standard offer suppliers, the incremental costs associated with line losses and congestion between the delivery points chosen by the suppliers and CL&P's service territory in Connecticut are the responsibility of CL&P's customers. The $132.5 million of incremental LMP costs incurred from March 1, 2003 through September 30, 2003 have been recorded as recoverable energy costs, and approximately $95.6 million has been billed to CL&P's customers and reflected in revenues through September 30, 2003. The remaining balance is included in recoverable energy costs, which collectively is a component of regulatory assets. Management believes that these congestion and line loss charges are unavoidable, are part of the prudent cost of providing regulated electric service in Connecticut and should be paid for by CL&P's customers. Accordingly, CL&P sought and received approval on May 1, 2003, for recovery of these costs through the energy adjustment clause (EAC), subject to refund. CL&P began recovery of the March 2003 LMP costs in its May 2003 billings and continues to bill LMP costs on a two-month lag. The DPUC directed CL&P to pursue legal remedies against its standard offer suppliers in an effort to assign liability for incremental LMP costs to those suppliers. The DPUC indicated that it will support CL&P's efforts and that CL&P's failure to aggressively pursue legal remedies may result in ultimate disallowance of recovery of LMP-related costs. The DPUC also required CL&P to obtain surety bonds, which are guaranteed by NU parent, for the $31.1 million of March 2003 and April 2003 incremental LMP costs. Amounts collected from customers beginning with May 2003 incremental LMP costs that were recovered in July 2003 were deposited into an escrow account. At September 30, 2003, $45.8 million was deposited in the escrow account and is included in restricted cash - LMP costs on the accompanying consolidated balance sheet. In response to the DPUC decision of May 1, 2003, CL&P has filed for a declaratory judgment from the FERC to determine whether CL&P's standard offer service suppliers are responsible for incremental LMP costs. Additionally, CL&P has withheld payment of all $132.5 million of incremental LMP costs to its standard offer service suppliers, pending resolution of this matter. Hearings on this issue before a FERC administrative law judge occurred in October 2003. As a result of these hearings, the parties agreed to a settlement conference before a FERC settlement judge, which occurred from November 4, 2003 to November 5, 2003. No settlement has been reached as of November 7, 2003. Resolution of this issue by the FERC will likely occur in 2004, and a FERC administrative law judge decision may be issued in the fourth quarter of 2003. Management continues to believe that these incremental LMP costs will ultimately be recovered from its customers based upon the legal interpretation of the standard offer supply contracts. Management will continue to evaluate the likelihood of recovery of these costs in the fourth quarter. Another factor affecting the level of CL&P's operating costs is the designation of certain generating units by ISO-NE as units needed for system reliability. Some companies have applied to the FERC for "reliability must run" (RMR) treatment for their units. There are two methods of RMR treatment that have been allowed by the FERC, both of which allow these units to receive cost of service-based payments in excess of their operational energy costs, that recognize their reliability value. The two methods allowed have provided certain generating units with the ability to collect non-energy related costs through fixed cost payments and/or through the submission of bid prices that include non-energy costs. The latter method provided these units with a temporary safe harbor from the ISO-NE price cap under certain circumstances. Prior to March 1, 2003, all RMR costs were spread across New England with all utilities being billed by ISO-NE based upon their share of New England's load. NU's regulated electric distribution companies were responsible for approximately 25 percent of these costs. Effective with the March 1, 2003 implementation of SMD, RMR costs were no longer spread across New England but rather they were allocated to the pricing zone in which the RMR unit is located. The only pricing zone currently experiencing an RMR cost increase in which NU's regulated electric distribution companies operate is Connecticut, where certain of the RMR units reside. Prior to RMR, other reliability costs have been approved for recovery by the DPUC in CL&P's 2001 Competitive Transition Assessment (CTA) reconciliation filing. RMR costs incurred by CL&P during 2002 totaling $7.8 million have been fully recovered from customers and are subject to review in CL&P's 2002 CTA reconciliation filing, which was filed on March 31, 2003. For the nine-month period ended September 30, 2003, CL&P incurred $40.3 million of RMR costs and recorded these costs as a regulatory asset. Management believes that these costs will be recovered in CL&P's 2003 CTA reconciliation filing. As part of the SMD implementation on March 1, 2003, ISO-NE now calculates line loss charges based on an economic formula and not on actual losses experienced. To date, ISO-NE has not filed its methodology for determining line loss charges with the FERC, and CL&P has been unable to verify the validity or accuracy of ISO-NE's billings. Accordingly, on July 23, 2003, CL&P filed a complaint with the FERC requesting that ISO-NE provide its methodology for determining such charges. In October 2003, the FERC rejected this complaint. On July 25, 2003, CL&P filed with the DPUC a request for approval of a formal recovery mechanism that would allow for the 2004 and beyond tracking and recovery of all Federally Mandated Congestion Costs (FMCC) as outlined in Connecticut Public Act No. 03-135 (the Act). The major cost components of FMCC are congestion costs, line losses and RMR costs. Management anticipates that this matter will be resolved by the DPUC by the end of 2003. NU Enterprises: Select Energy continues to provide 50 percent of CL&P's standard offer service. If it is ultimately concluded that some or all of the incremental LMP costs, which began on March 1, 2003, are the responsibility of the standard offer service suppliers, NU Enterprises' and NU's pre-tax earnings for the nine months ended September 30, 2003, would be reduced by up to $71 million with no incremental impact on Select Energy's cash flows. Management currently expects Select Energy's share of incremental LMP costs for 2003 to be approximately $90 million, depending on the level of line losses and congestion costs experienced. Management believes that these costs are not contractually Select Energy's responsibility, but will continue to assess the collectibility of Select Energy's accounts receivable from CL&P based on developments at the FERC. Select Energy's standard offer service contract with CL&P expires on December 31, 2003. NU Enterprises' and NU's 2003 earnings estimates do not include the impact of these incremental LMP costs. For information regarding commitments and contingencies related to the accounting for the implementation of SMD, see Note 4A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements. NRG Exposures - ------------- Certain subsidiaries of NU have entered into various transactions with subsidiaries of NRG. On May 14, 2003, NRG and certain of its subsidiaries filed voluntary bankruptcy petitions in the United States Bankruptcy Court for the Southern District of New York. NRG-related exposures to certain subsidiaries of NU as a result of these transactions are as follows: Standard Offer Service Contract: NRG Power Marketing, Inc. (NRG-PM) has a contract with CL&P to supply 45 percent of CL&P's standard offer service load through December 31, 2003. NRG-PM attempted to terminate the contract with CL&P, but the FERC ordered NRG-PM to continue serving CL&P under its standard offer supplier contract. Subsequently, NRG-PM received a temporary restraining order from the United States District Court for the Southern District of New York (District Court) and stopped serving CL&P with standard offer supply on June 12, 2003. NRG-PM was ultimately ordered by the FERC and the District Court to resume serving CL&P's standard offer service load and did so on July 2, 2003. During the period NRG-PM did not serve CL&P under its standard offer service contract, CL&P purchased power from the spot market at prices in excess of NRG-PM's contract price. This excess amounted to $7.9 million and was collected by CL&P from its customers. As a result of the settlement described below, this amount will be collected from NRG-PM. On November 4, 2003, CL&P, NRG, the NRG Creditors' Committee, the DPUC, the Office of Consumer Counsel and the attorney general of Connecticut entered into a comprehensive settlement agreement. Under the settlement agreement, which is subject to the approval of the bankruptcy court and the FERC, NRG will continue to deliver power to CL&P under the terms and conditions of the standard offer service contract through the end of its term, which is December 31, 2003. The disputes relating to responsibility for incremental LMP costs will be determined by the District Court and the FERC respectively, with payment, if any, to be made to NRG from amounts withheld and to be withheld from NRG by CL&P. CL&P will also retain the $7.9 million withheld from NRG for replacement power purchased by CL&P during the period June 12, 2003 through July 2, 2003. The parties will exchange releases of all claims relating to the standard offer service contract. Pre-March 1, 2003 Congestion Charges: In November 2001, CL&P filed suit against NRG in Connecticut Superior Court seeking judgment for unpaid pre- March 1, 2003, congestion charges under its standard offer supply contract. On August 5, 2002, CL&P withheld the then unpaid congestion charges from payments due to NRG for standard offer service and continues to withhold these amounts. The total amount of congestion costs withheld from NRG was $27.5 million. If it is ultimately concluded that CL&P is responsible for pre-March 1, 2003 congestion costs, management believes CL&P would be allowed to recover these costs from its customers. Station Service: Since December 1999, CL&P has provided NRG's Connecticut generating plants with station service, which includes energy and/or delivery services provided when a generator is off-line or unable to satisfy its station service requirements. Pursuant to the parties' interconnection agreement dated July 1, 1999, CL&P provides this service at DPUC-approved retail rates. NRG has disputed its obligation and has refused to pay CL&P but has stated that it intends to assume the station service contract in bankruptcy proceedings. NRG and CL&P stipulated to an order in bankruptcy court requiring the determination of the amount owed by NRG for station service under binding arbitration. If NRG assumes the contract, NRG will be required to pay the amount determined in the arbitration to CL&P. Management will continue to pursue recovery from NRG of the station service balance, including $4.2 million NRG placed in an escrow account related to this matter. During the second quarter of 2003, as a result of NRG's bankruptcy, the amount due from NRG in excess of the escrow amount was reserved. Management believes that amounts not collected from NRG are ultimately recoverable from CL&P's customers. Therefore, a regulatory asset of $10.6 million was recorded. At September 30, 2003, NRG owed CL&P $15.4 million for station service. Through September 30, 2003, legal costs incurred by CL&P related to NRG's bankruptcy amounted to $1.6 million. This amount has also been recorded as a regulatory asset, and CL&P will continue to defer these legal costs as they are incurred. Meriden Gas Turbines, LLC: Yankee Gas, E.S. Boulos Company (Boulos), which is a subsidiary of NGS, and CL&P have exposures to Meriden Gas Turbines, LLC (MGT), an NRG subsidiary that is not included in NRG's voluntary bankruptcy proceedings petition. Yankee Gas has incurred and expended costs in excess of $16 million in the construction of a natural gas pipeline to a generating plant that MGT was constructing. Yankee Gas drew down on a $16 million letter of credit when MGT stated that it was abandoning construction of the generating plant. NRG has contested the draw down on the letter of credit in a lawsuit filed in Connecticut Superior Court. Yankee Gas has a counterclaim pending against MGT to recover additional monies in accordance with the contract that are in excess of the $16 million letter of credit. Boulos has a 50 percent interest in a joint venture that was building switchyards for the MGT generating plant. To date, Boulos has $0.4 million of accounts receivable from performing its 50 percent share of the joint venture's work on the MGT. In addition, the joint venture has outstanding payables of $2.6 million for which it has corresponding receivables from the general contractor; Boulos' share equaling $1.3 million. The joint venture has commenced a legal proceeding against the general contractor to collect the amounts owed. The joint venture is also a party to a mechanics lien foreclosure action in which one of its subcontractors is attempting to foreclose upon a mechanics lien filed on the MGT generating plant. Boulos' total exposure to NRG on this project is $1.7 million. MGT also currently owes CL&P $0.5 million for work on the South Kensington switching station, which was to be the interconnection point for the MGT generating plant. Management does not expect that the resolution of the aforementioned MGT disputes will have a material adverse effect on the financial condition or results of operations of NU and its subsidiaries. NU Enterprises - -------------- Subsidiaries: NU Enterprises, Inc. is the parent company of Select Energy, NGC, SESI, NGS, and their respective subsidiaries, and Woods Network, which are collectively referred to as "NU Enterprises." The ongoing generation operations of HWP are also included in the results of NU Enterprises. Select Energy engages in wholesale and retail energy marketing activities and limited energy trading activities for price discovery and risk management of wholesale activities. NU Enterprises includes 1,438 MW of generation capacity, consisting of 1,291 MW at NGC and 147 MW at HWP, which are used to support Select Energy's merchant energy business. In October 2003, NU revised an earlier application made to the SEC seeking to expand its ability to support its unregulated businesses. The new application primarily seeks to 1) reclassify Select Energy and Select Energy New York, Inc. (SENY) as allowable retained businesses under the Public Utility Holding Company Act of 1935 (1935 Act) not subject to the limitations of a 15 percent capitalization test imposed by the Securities and Exchange Commission's (SEC) 1935 Act Rule 58 (Rule 58 Investment Limit), 2) permit NU to guarantee the obligations of its unregulated businesses up to $750 million through September 30, 2006, and 3) increase its allowable investments in exempt wholesale generators (EWGs) from $481 million to $1 billion. If granted, the SEC's order would reduce the Rule 58 Investment Limit by the amount of NU's investment in Select Energy and SENY at June 30, 2003, but not limit NU's future investment in Select Energy and SENY. NU has no present plans to significantly expand its EWG portfolio at this time. However, if an investment opportunity becomes available, NU will be able to pursue it within the new allowable EWG investment level. NU expects SEC approval in late 2003 or early 2004. SESI performs energy management services for large industrial, commercial and institutional facilities, including the United States Department of Defense, and engages in energy related construction services. NGS operates and maintains NGC's and HWP's generation assets and provides third-party electrical and engineering contracting services. Outlook: Financial performance at NU Enterprises improved significantly in the first nine months of 2003 compared to the same period in 2002. The wholesale business, which is part of NU Enterprises' merchant energy business line, has obtained two significant contracts since the second quarter of 2003. Select Energy has been awarded a contract to provide over 700 MW of default service to residential, commercial and industrial customers of Massachusetts Electric Company and Nantucket Electric Company, subsidiaries of National Grid Company. The contract period, which begins on November 1, 2003 and runs through October 31, 2004, is expected to generate revenues in excess of $100 million. The second contract calls for Select Energy to provide approximately 40 MW of last resort service to customers of Narragansett Electric Company from September 1, 2003 to August 31, 2004 with expected revenues of approximately $6.5 million. Management currently believes that the wholesale business will meet its 2003 net income estimate of between $27 and $30 million. To meet this estimate, the wholesale business will need to successfully manage its portfolio of contracts. For the first nine months of 2003, the wholesale business produced net income of $23.9 million. The wholesale business is expected to have net income in the fourth quarter of between $3 million and $6 million. The second business included in NU Enterprises' merchant energy business is the retail marketing business, which also improved its financial performance in 2003 compared to 2002. For the first nine months of 2003, the retail marketing business produced a net loss of $1.6 million compared with a net loss of $26.3 million in 2002. Retail marketing is also expected to have a net loss in the fourth quarter of between $0.4 million and $2.4 million resulting in a net loss in the range of $2 million to $4 million for the year. Intercompany Transactions: For the first nine months of 2003, CL&P's standard offer service purchases from Select Energy represented approximately $465 million of total NU Enterprises' revenues. Other transactions between CL&P and Select Energy amounted to approximately $101 million in revenues for Select Energy in the first nine months of 2003. Select Energy will continue to provide standard offer service for its affiliate WMECO through December 31, 2003. WMECO's purchases from Select Energy represented approximately $110 million of NU Enterprises' revenues in the first nine months of 2003. These amounts are eliminated in consolidation. Total Select Energy wholesale full requirements revenue for the first nine months of 2003 were $1.2 billion. NU Enterprises' Market and Other Risks - -------------------------------------- Overview: For further information on risk management activities, see "Competitive Energy Subsidiaries' Market and Other Risks" in NU's combined report on Form 10-K. Risk management within Select Energy is organized by management to address the market, credit and operational exposures arising from the company's merchant energy business lines: wholesale (which includes limited energy trading for market and price discovery purposes) and retail marketing. The framework and degree to which these risks are managed and controlled is consistent with the limitations imposed by NU's Board of Trustees as established and communicated in NU's risk management policies and procedures. Wholesale and Retail Marketing: Select Energy manages its portfolio of wholesale and retail marketing contracts and assets to maximize value while maintaining an acceptable level of risk. At forward market prices in effect at September 30, 2003, the wholesale portfolio, which includes the CL&P standard offer service contract that extends through December 31, 2003 and other contracts that extend to 2013, had a positive fair value. This positive fair value indicates a positive impact on Select Energy's gross margin in the future. However, there may be significant volatility in the energy commodities markets that may impact this position between now and when the contracts are settled. Accordingly, there can be no assurances that Select Energy will realize the gross margin corresponding to the present positive fair value on its wholesale portfolio. The gross margin realized could be at a level that is not sufficient to cover Select Energy's other operating costs, including the cost of corporate overhead. Hedging: For information on derivatives used for hedging purposes and nontrading derivatives, see Note 2, "Derivative Instruments, Market Risk and Risk Management," to the consolidated financial statements. Energy Trading Activities Within Wholesale: Energy trading transactions at Select Energy include financial transactions and physical delivery transactions for electricity, natural gas and oil in which Select Energy is attempting to profit from changes in market prices. Energy trading contracts are recorded at fair value, and changes in fair value impact net income. Over the past year, Select Energy has significantly reduced its trading activities, and trading now mainly supports the wholesale business for price discovery, market intelligence and deal execution. At September 30, 2003, Select Energy had trading derivative assets of $89 million and trading derivative liabilities of $52.8 million on a counterparty- by- counterparty basis, for a net positive position of $36.2 million for the entire trading portfolio. These amounts are combined with other derivatives and are included in derivative assets and derivative liabilities on the accompanying consolidated balance sheets. Information regarding nontrading and other derivatives is included in Note 2, "Derivative Instruments, Market Risk and Risk Management," to the consolidated financial statements. There can be no assurances that Select Energy will actually realize cash corresponding to the present positive net fair value of its trading portfolio. Numerous factors could either positively or negatively affect the realization of the net fair value amount in cash. These include the volatility of commodity prices, changes in market design or settlement mechanisms, the outcome of future transactions, the performance of counterparties, and other factors. Select Energy has policies and procedures requiring all trading positions to be marked-to-market at the end of each business day. Controls are in place segregating responsibilities between the individuals actually trading (front office) and those confirming the trades (middle office). The determination of the portfolio's fair value is the responsibility of the middle office independent from the front office. The methods used to determine the fair value of energy trading contracts are identified and segregated in the table of fair value of contracts at September 30, 2003. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange futures and options that are marked to closing exchange prices; 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity or natural gas, and are marked to the mid-point of bid and ask market prices; 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. Select Energy currently has one contract for which fair value is determined based upon an other valuation method. Broker quotes for electricity are available through the year 2005. Broker quotes for natural gas are available through 2013. Generally, valuations of short-term contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations based on models or other methods for longer-term contracts are less certain. Accordingly, there is a risk that contracts will not be realized at the amounts recorded. However, Select Energy has sourced substantially all of the trading contracts that have maturities in excess of four years. Because these contracts are sourced, changes in the value of these contracts due to changes in commodity prices are not expected to impact Select Energy's earnings. As of and for the three and nine months ended September 30, 2003, the sources of the fair value of trading contracts and the changes in fair value of these trading contracts are included in the following tables. Intercompany transactions are eliminated and not reflected in the amounts below. - ------------------------------------------------------------------------------- Fair Value of Trading Contracts - ------------------------------------------------------------------------------- (Millions of Dollars) At September 30, 2003 - ------------------------------------------------------------------------------- Maturity Maturity of Maturity in Total Less than One to Four Excess of Fair Sources of Fair Value One Year Years Four Years Value - ------------------------------------------------------------------------------- Prices actively quoted $ - $ 0.1 $ - $ 0.1 Prices provided by external sources 7.9 8.8 16.5 33.2 Prices based on models or other valuation methods - 2.9 - 2.9 - ------------------------------------------------------------------------------- Totals $ 7.9 $11.8 $16.5 $36.2 - ------------------------------------------------------------------------------- The fair value of energy trading contracts decreased by $8.8 million from $45 million at June 30, 2003 to $36.2 million at September 30, 2003. The change in fair value of contracts since June 30, 2003, primarily represents a credit reserve established in the third quarter of 2003, which reduced the fair value of contracts. The fair value of energy trading contracts decreased by $4.8 million from $41 million at January 1, 2003 to $36.2 million at September 30, 2003. For the nine months ended September 30, 2003, the change in fair value attributable to changes in valuation techniques and assumptions was due to a change in the discount rate management uses to determine the fair value of trading contracts. In the second quarter of 2003, the rate was changed from a fixed rate of 5 percent to a market-based LIBOR discount rate. - ------------------------------------------------------------------------------- Total Fair Value - ------------------------------------------------------------------------------- Three Months Ended Nine Months Ended (Millions of Dollars) September 30, 2003 September 30, 2003 - ------------------------------------------------------------------------------- Fair value of trading contracts outstanding at the beginning of the period $45.0 $41.0 Contracts realized or otherwise settled during the period (2.2) (7.2) Fair value of new contracts when entered into during the period - - Changes in fair value attributable to changes in valuation techniques and assumptions - 2.3 Changes in fair value of contracts (6.6) 0.1 - ------------------------------------------------------------------------------- Fair value of trading contracts outstanding at the end of the period $36.2 $36.2 - ------------------------------------------------------------------------------- Changing Market: The breadth and depth of the market for energy trading and marketing products in Select Energy's market continues to be adversely affected by the withdrawal or financial weakening of a number of companies who have historically done significant amounts of business with Select Energy. In general, the market for such products has become shorter term in nature with less liquidity, market pricing information is becoming less readily available, and participants are more often unable to meet Select Energy's credit standards without providing cash or letter of credit support. Select Energy is being adversely affected by these factors, and there could be a continuing adverse impact on Select Energy's business. The decrease in the number of counterparties participating in the market for long-term energy contracts also continues to impact Select Energy's ability to estimate the fair value of its long-term wholesale energy contracts. Changes are occurring in the administration of transmission systems and system operators in territories in which Select Energy does business. Regional transmission organizations are being contemplated, and SMD was implemented in New England on March 1, 2003. As more information regarding these market changes becomes available, there could be additional adverse effects that management cannot determine at this time. Counterparty Credit: Counterparty credit risk relates to the risk of loss that Select Energy would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties' financial conditions (including credit ratings), collateral requirements under certain circumstances (including cash advances, letters of credit, and parent guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to Select Energy entering into contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. At September 30, 2003, approximately 80 percent of Select Energy's counterparty credit exposure to wholesale and trading counterparties was cash collateralized or rated BBB- or better. Another five percent of the counterparty credit exposure was to unrated municipalities. Asset Concentrations: At September 30, 2003, positions with two counterparties collectively represented approximately $51 million, or 57 percent, of the $89 million trading derivative assets. The largest counterparty's position is secured with letters of credit and cash collateral. Select Energy holds an investment grade parent guarantee on the second counterparty's position. None of the other counterparties represented more than 10 percent of trading derivative assets at September 30, 2003. Select Energy's Credit: A number of Select Energy's contracts require the posting of additional collateral in the form of cash or letters of credit in the event NU's ratings were to decline and in increasing amounts dependent upon the severity of the decline. At NU's present investment grade ratings, Select Energy has not had to post any collateral based on credit downgrades. Were NU's unsecured ratings to decline two to three levels to sub-investment grade, Select Energy could, under its present contracts, be asked to provide approximately $237 million of collateral or letters of credit to various unaffiliated counterparties and approximately $75 million to several independent system operators and unaffiliated local distribution companies, which management believes NU would currently be able to provide. NU's credit ratings outlooks are currently stable or negative, but management does not believe that at this time there is a significant risk of a ratings downgrade to sub-investment grade levels. Utility Group Business Development and Capital Expenditures - ----------------------------------------------------------- On July 14, 2003, the Connecticut Siting Council (CSC) approved a 345,000 volt transmission line project from Bethel, Connecticut to Norwalk, Connecticut, proposed in October 2001 by CL&P. The configuration of the new transmission line, enhancements to an existing 115,000 volt transmission line, and work in related substations are estimated to cost approximately $200 million. The line would help address the difficulties in serving the load in southwest Connecticut that creates high LMP costs in Connecticut. Unless judicial appeals delay the project, CL&P expects to begin construction on portions of the project in the fourth quarter of 2003. This project is exempt from the State of Connecticut's moratorium on the approval of new electric and natural gas transmission projects. At September 30, 2003, CL&P has capitalized approximately $13.1 million related to this project. On October 9, 2003, CL&P and United Illuminating (UI) filed for approval of a separate 345,000 volt transmission line from Norwalk, Connecticut to Middletown, Connecticut. Estimated construction costs of this project are approximately $620 million. CL&P will jointly site this project with UI and CL&P will own 80 percent, or approximately $496 million, of the project. This project is also exempt from the State of Connecticut's moratorium on the approval of new electric and natural gas transmission projects. CL&P expects the CSC to rule on the application in 2004 and for construction to take place from 2005 through 2007. At September 30, 2003, CL&P has capitalized approximately $7.6 million related to this project. In September 2002, the CSC approved a plan to replace an undersea electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, at an estimated cost of $80 million. CL&P and the Long Island Power Authority each own 50 percent of the line. The project still requires federal and New York state approvals. Given the approval process, changing pricing and operational rules in the New England and New York energy markets and pending business issues between the parties, the expected in-service date remains under evaluation. This project is also exempt from the State of Connecticut's moratorium on the approval of new electric and natural gas transmission projects. At September 30, 2003, CL&P has capitalized approximately $5.9 million related to this project. Yankee Gas had previously sought rate approval from the DPUC to build a 2.0 billion cubic foot liquefied natural gas storage and production facility in Waterbury, Connecticut. On October 24, 2003, Yankee Gas received a draft decision from the DPUC approving the construction and operation of a 1.2 billion cubic foot liquefied natural gas storage and production facility. Construction of the facility, which is expected to take approximately three years, could begin in early 2004. The draft decision allows for the deferral of prudently incurred costs related to the project and requires Yankee Gas to file a rate case to recover these investments when the facility is placed in service. This project is also exempt from the State of Connecticut's moratorium on the approval of new electric and natural gas transmission projects. At September 30, 2003, Yankee Gas has capitalized approximately $1.5 million related to this project. A final decision from the DPUC is scheduled for November 2003. In October 2003, the FERC approved the sale of Connecticut Valley Electric Company's (CVEC) assets to PSNH. CVEC is a subsidiary of Central Vermont Public Service Corporation (CVPS). The sale is expected to close in December 2003 and be effective January 1, 2004. The purchase price will be the book value of CVEC's assets, currently estimated at approximately $9 million and an additional $21 million to terminate the above-market wholesale power purchase agreement CVEC has with CVPS. The $21 million payment will be recovered over the next several years from PSNH's customers as a Part 3 stranded cost. Restructuring and Rate Matters - ------------------------------ Utility Group: On August 26, 2003, NU's electric operating companies filed their first transmission rate case at the FERC since 1995. In the filing, NU requested implementation of a formula rate that would allow recovery of increasing transmission expenditures on a timelier basis and that the changes, including a $23.7 million annual rate increase through 2004, take effect on October 27, 2003. NU asked the FERC to maintain NU's existing 11.75 percent return on equity (ROE) until an ROE for the New England Regional Transmission Organization (RTO) is established by the FERC. On October 22, 2003, the FERC approved this filing implementing the proposed rates subject to refund effective on October 28, 2003. On October 31, 2003, ISO-NE, along with NU and six other New England transmission companies, filed a proposal with the FERC to create a RTO for New England. The RTO is intended to strengthen the independent and efficient management of the region's power system while ensuring that consumers in New England continue to have the most reliable system possible to realize the benefits of a competitive wholesale market. ISO-NE, as an RTO, will have a new independent governance structure, and will also become the transmission provider for New England by exercising operational control over New England's transmission facilities pursuant to a detailed contractual arrangement with the New England transmission owners. Under this contractual arrangement, the RTO will have clear authority to direct the transmission owners to operate their facilities in a manner that preserves system reliability, including requiring transmission owners to expand existing transmission lines or build new ones when needed for reliability. Transmission owners will retain their rights over revenue requirements, rates and rate designs. The filing requests that the FERC approve the RTO arrangements for an effective date of March 1, 2004. In a separate filing made on November 4, 2003, NU along with six other New England transmission owners requested, consistent with the FERC's pricing policy for RTOs and Order 2000 compliant independent system operators, that the FERC approve a single ROE for regional and local rates that would consist of a base ROE as well as incentive adders of 50 basis points for joining an RTO and 100 basis points for constructing new transmission facilities approved by the RTO. If the FERC approves the request, the transmission owners would receive a 13.3 percent ROE for existing transmission facilities and a 14.3 percent ROE for new transmission facilities. Connecticut - CL&P: Public Act No. 03-135 and Rate Proceedings Rate Case: On June 25, 2003, the Governor of Connecticut signed the Act into law. The Act amended Connecticut's 1998 electric utility industry legislation. Among key features, the Act created a Transitional Standard Offer (TSO) period from 2004 through 2006 that allows the base rate cap for customers to return to 1996 levels, which is an increase of up to 11.1 percent. If energy supply costs exceed levels established in the TSO rate, these costs will be recovered through an energy adjustment clause or through the FMCC charge in the case of incremental LMP costs. On July 1, 2003, CL&P made a filing with the DPUC to establish TSO service and to set the TSO rates equal to December 31, 1996 total rate levels. Under the Act, the DPUC must establish the TSO rates no later than December 15, 2003, with an effective date for the TSO rates of January 1, 2004. To procure TSO service, an auction process was conducted by CL&P. On October 29, 2003, the auction process was completed and CL&P filed the results of the auction process with the DPUC. The Act also required CL&P to file a four-year transmission and distribution plan with the DPUC. Accordingly, on August 1, 2003, CL&P filed a rate case that amended rate schedules and proposed changes in electric distribution service and transmission service rates to reflect a four-year plan for the provision of such services. The amended rate schedules were designed to increase CL&P's annual distribution component of revenues by the following approximate amounts, beginning January 1, 2004, through January 1, 2007: - ------------------------------------------------------------------------------- Incremental Percentage Increase in Year Incremental Increase Total TSO Rates - ------------------------------------------------------------------------------- 2004 $133.5 million 6.0% 2005 23.2 million 1.0% 2006 24.0 million 1.0% 2007 24.1 million 1.0% - ------------------------------------------------------------------------------- In its rate case, CL&P cited the need for rate increases to recover 1) increased costs of providing service, including higher pension and health care costs, 2) an approximately $250 million per year capital program for distribution, and 3) the recruitment and training of new workers as a result of the aging of the current skilled electric craft worker population. CL&P also requested a tracking mechanism that could annually adjust the electric transmission rates to reflect FERC-approved transmission tariffs. However, if the transmission rate tracking mechanism filing process does not prove to be acceptable to the DPUC, CL&P proposed amended annual rate schedules in its rate application that will be designed to adjust CL&P's rates for transmission costs during the rate period. Hearings on this filing were held in September 2003 and October 2003 with a final decision expected to be issued in December 2003. Seabrook Disposition of Proceeds: CL&P sold its share of the Seabrook nuclear unit on November 1, 2002. CL&P received $37 million and recorded a gain on the sale of approximately $16 million. The gain was recorded as a regulatory liability and, when offset by the decommissioning top off and other adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale. This filing described CL&P's treatment of its share of the proceeds from the sale. Hearings in this docket were held in September 2003, and a final decision is scheduled to be issued in December 2003. Management does not expect the final decision to have a material effect on CL&P's net income or its financial position. CTA and System Benefits Charge (SBC) Reconciliation: On April 3, 2003, CL&P filed its annual CTA and SBC reconciliation with the DPUC. For the year ended December 31, 2002, total CTA revenues and excess Generation Services Charge (GSC) revenues exceeded the CTA revenue requirement by approximately $93.5 million. This amount is recorded as a regulatory liability and is included in other deferred credits on the accompanying consolidated balance sheet. CL&P has proposed that a portion of the CTA/GSC overrecovery be utilized to reduce the nuclear stranded cost regulatory asset and that the remaining amount be carried forward through 2003. For the same period, SBC revenues exceeded the SBC revenue requirement by approximately $22.4 million. In compliance with a prior decision of the DPUC, a portion of the SBC overrecovery was applied to regulatory assets, and the remaining overrecovery of $18.6 million was applied to the CTA. Management expects a final decision from the DPUC in this docket by the end of 2003. Management does not expect the final decision to have a material effect on CL&P's net income or its financial position. Connecticut - Yankee Gas: Infrastructure Expansion Rate Mechanism (IERM): On June 25, 2003, the DPUC issued a final decision in the 2002 IERM docket. The DPUC concluded that the basic concept of IERM is valid, appropriate and beneficial. The DPUC ordered Yankee Gas to provide a credit to customers for 2002 and 2003 overrecoveries during December 2003 through February 2004. As ordered, Yankee Gas submitted a compliance filing with the DPUC on August 15, 2003 which included an estimate of total overrecoveries for 2002 and 2003 of approximately $5.9 million. This amount has been recorded as a regulatory liability. On September 11, 2003, the DPUC approved Yankee Gas' compliance filing, including the calculation of the $5.9 million in estimated overrecoveries to be refunded from December 2003 through February 2004. On October 1, 2003, Yankee Gas filed with the DPUC its 2004 IERM compliance filing. This filing is required annually on October 1 of each year to provide a reconciliation of the system expansion program and the earnings sharing mechanism projection. At this time, the DPUC has not issued a schedule for this docket. New Hampshire: Transition Service: On September 12, 2003, in accordance with the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement) and state law, PSNH filed for an updated transition service rate of $0.0513 per kilowatt-hour (kWh), subject to adjustment, for commercial, industrial, and residential customers for the period February 2004 through January 2005. The transition service rate is $0.0467 per kWh for industrial customers and $0.0460 per kWh for residential and small general service customers. Both rates are for the period February 2003 through January 2004. In accordance with state law, these rates are to be PSNH's actual, prudent and reasonable costs of providing such power. Hearings are scheduled for late November 2003. The transition service rates currently in effect are not fully recovering PSNH's generation and purchased-power costs, including earning a return on PSNH's generation investment. Transition service underrecoveries, in addition to other stranded cost components of the Stranded Cost Recovery Charge (SCRC), amounted to approximately $24 million since the start of restructuring on May 1, 2001 through September 30, 2003. This amount excludes the gain on the sale of Seabrook. Delivery Rate Case: PSNH's delivery rates are fixed by the Restructuring Settlement until February 1, 2004. Under the Restructuring Settlement, PSNH is required to file a rate case by December 31, 2003 to determine PSNH's delivery rates. SCRC Reconciliation Filing: On May 1, 2003, PSNH filed a SCRC reconciliation filing for the period January 1, 2002, through December 31, 2002 with the New Hampshire Public Utilities Commission (NHPUC). This filing included the reconciliation of stranded cost revenues with stranded costs, the reconciliation of transition service revenues with transition service costs, and a net proceeds calculation related to the sale of North Atlantic Energy Corporation's share of Seabrook and the subsequent transfer of those net proceeds to PSNH. Upon the completion of discovery and technical sessions with NHPUC staff and the New Hampshire Office of the Consumer Advocate (OCA), PSNH, the NHPUC Staff and the OCA entered into a stipulation and settlement agreement that was filed with the NHPUC on September 15, 2003. An order from the NHPUC approving the settlement agreement was received in October 2003. The settlement agreement did not have a material impact on PSNH's net income or its financial position. Massachusetts: Transition Cost Reconciliation: On March 31, 2003, WMECO filed its 2002 annual transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE). This filing reconciled the recovery of generation-related stranded costs for calendar year 2002 and included the renegotiated purchased power contract related to the Vermont Yankee nuclear unit. On July 15, 2003, the DTE issued a final order on WMECO's 2001 annual transition cost reconciliation, which addressed WMECO's cost tracking mechanisms. As part of that order, the DTE directed WMECO to revise its 2002 annual transition cost reconciliation filing. The revised filing was submitted to the DTE on September 23, 2003. Hearings were held in October 2003, and a final decision from the DTE is expected in the first half of 2004. Management does not expect the outcome of this docket to have a material adverse impact on WMECO's net income or its financial position. For information regarding commitments and contingencies related to restructuring and rate matters, see Note 4A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements. Critical Accounting Policies and Estimates Update - ------------------------------------------------- Accounting for Incremental LMP Costs: The determination of whether CL&P's retail customers or CL&P's standard offer service suppliers are responsible for incremental LMP costs as a result of the implementation of the SMD in New England and the impacts on Select Energy, NU Enterprises, CL&P and NU are described in "Impacts of Standard Market Design" included in this Management Discussion and Analysis. There are significant accounting conclusions related to the incremental LMP dispute. Management continues to believe that the incremental LMP costs recorded as a regulatory asset are probable of future recovery from customers and has recorded a regulatory asset for these costs on CL&P's financial statements. Management must maintain this belief as CL&P argues before the FERC that the incremental LMP costs should be the responsibility of the standard offer suppliers as ordered by the DPUC. If at anytime before the regulatory asset is fully recovered management cannot conclude that the costs are probable of future recovery, then the remaining regulatory asset would be written off. To the extent incremental LMP costs have been recovered through the EAC, management must determine whether or not a regulatory liability is required. Incremental LMP costs incurred and recovered are currently included in accounts payable to the standard offer service suppliers. To the extent CL&P is unable to collect these costs from its customers, CL&P would not pay the suppliers for these costs which are included in accounts payable. As a result, CL&P would have no negative earnings impact; rather Select Energy would be required to write off its accounts receivable from CL&P and record a corresponding loss. Determining what party will ultimately be responsible for incremental LMP costs requires a significant amount of judgment. Hearings on this issue before a FERC administrative law judge occurred in October 2003. As a result of these hearings, the parties agreed to a settlement conference before a FERC settlement judge, which occurred from November 4, 2003 to November 5, 2003. No settlement has been reached as of November 7, 2003. Resolution of this issue by the FERC will likely be in 2004, and a FERC administrative law judge decision may be issued in the fourth quarter of 2003. At this point, management believes that it is premature to record a reserve for incremental LMP costs. Management continues to believe that these incremental LMP costs will ultimately be recovered from CL&P's customers based upon its legal interpretation of standard offer supply contracts. Management will continue to evaluate the likelihood of recovery of these costs in the fourth quarter. All developments through the time NU's 2003 annual report on Form 10-K is filed will be evaluated, and any resulting impacts on the amounts included in NU's financial statements will be reflected in 2003 earnings and the December 31, 2003 consolidated balance sheet. Adjustments to Estimates of Unbilled Revenues: Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not been billed. Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed. Billed revenues are based on meter readings. Unbilled revenues are estimated monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity or gas delivered to the system and applies a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses to calculate the total estimated monthly sales to customers. The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales. Small differences in the actual DE factor to the estimated DE factor can have a significant impact on estimated unbilled revenue amounts. In the third quarter of 2003, the unbilled sales estimates for all Utility Group companies were tested using the cycle method and will be tested at least annually hereafter. The cycle method is historically more accurate than the requirements method, when used in a mostly weather-neutral month. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method testing indicated that the estimate of total unbilled revenues should be adjusted, which resulted in a net positive after-tax earnings impact of approximately $5.7 million in the third quarter of 2003. The positive after-tax impacts on CL&P, PSNH, and WMECO were $7.2 million, $3.3 million, and $0.3 million, respectively. There was a negative after-tax impact on Yankee Gas of $5.1 million. The estimate of unbilled revenues is sensitive to numerous factors that can impact the amount of energy that is ultimately delivered to customers. Estimating the impact of these factors is complex and requires management judgment. Energy Trading and Derivative Accounting: In April 2003, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amended existing derivative accounting guidance. SFAS No. 149 incorporates interpretations that were included in previous Derivative Implementation Group (DIG) guidance, clarifies certain conditions, and amends other existing pronouncements. It was effective for contracts entered into or modified after June 30, 2003. The new rules indicate that derivative contracts that are subject to unplanned netting and can be settled for cash versus physical delivery would no longer qualify for the normal purchases and sales exception, which would require fair value accounting. Management has determined that the adoption of SFAS No. 149 did not change NU's accounting for wholesale and retail marketing contracts that were entered into prior to July 1, 2003 or affect the ability of NU to elect the normal purchases and sales exception. Emerging Issues Task Force (EITF) Issue No. 03-11 "Reporting Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and 'Not Held for Trading Purposes' as Defined in EITF Issue No. 02-3, 'Issues related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities'" was derived from EITF Issue No. 02-3, which requires net reporting in the income statement in revenues of energy trading activities. Issue No. 03-11 addresses income statement classification of derivatives that are not related to energy trading activities. Prior to Issue No. 03-11, there was no specific accounting guidance that addressed the classification in the income statement of Select Energy's retail marketing and wholesale contracts, many of which are derivatives. The only applicable guidance was EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." The indicators of gross revenue reporting include whether the entity is the primary obligor in the arrangement, whether the entity has inventory or credit risk, latitude in establishing price, and discretion in supplier selection. Indicators of net revenue reporting are whether the supplier is in the primary obligor in the arrangement, the entity earns a fixed amount and the supplier has credit risk. On July 31, 2003, the EITF reached a consensus in Issue No. 03-11 that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on the relevant facts and circumstances. The EITF indicated that the indicators set forth in Issue No. 99-19 should continue to be considered and provided no new accounting guidance. Additionally, the consensus recommends disclosure of where the gains and losses are recorded in the income statement, and whether they are presented on a net or gross basis. Issue No. 03-11 is effective for NU prospectively on October 1, 2003. Select Energy currently reports the settlement of short-term and long-term derivative contracts that are not held for trading purposes on a gross basis, generally with sales in revenues and purchases in expenses. Short-term sales and purchases represent power that is purchased to serve full requirements contracts but is ultimately not needed based on the actual load of the full requirements customers. This excess power is sold to the independent system operator or to other counterparties. Management is currently evaluating the impact of the consensus in Issue No. 03-11 as it relates to income statement classification of Select Energy's short-term energy purchases and sales. Management will complete this evaluation in the fourth quarter in accordance with Issue No. 03-11. If management determines that revenues and expenses related to short-term sales and purchases should be reported net, then there could be a significant reduction in both Select Energy's revenues and expenses with no operating income or net income impact. For the first nine months of 2003, short-term and non-requirements sales amounted to approximately $600 million. On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning of "not clearly and closely related regarding contracts with a price adjustment feature" as it relates to the election of the normal purchase and sales exception to derivative accounting. The implementation of this guidance is required for the fourth quarter of 2003 for NU. Management is currently evaluating the impacts of Issue No. C-20, but believes that when it is implemented, Issue No. C-20 will likely result in CL&P recording the fair value of two existing power purchase contracts as derivative liabilities with offsetting regulatory assets, as these contracts are part of stranded costs and as management believes that these costs will continue to be recovered in rates. Management's preliminary estimates of the fair values of these long- term power purchase contracts indicate that the contracts have a combined negative fair value of approximately $16 million. Accounting for RMS Variable Interest Entity: On June 30, 2001, NU sold RMS for $10 million in the form of convertible cumulative 5 percent preferred stock and a warrant to buy 25 percent of the outstanding common stock of RMS for $1,000 expiring in 2021. NU also agreed to guarantee a $3 million line of credit for RMS through 2005. In the second and third quarters of 2003, RMS began drawing on this line of credit and the balance outstanding at September 30, 2003 was $0.5 million. In January 2003, the FASB issued FIN 46 which was effective for NU on July 1, 2003 (NU did not electively delay implementation until the fourth quarter of 2003). RMS is a variable interest entity (VIE), as defined. FIN 46 requires that the party to a VIE that absorbs the majority of the VIE's losses, defined as the "primary beneficiary," consolidate the VIE. Upon adoption of FIN 46, management determined that NU is the "primary beneficiary" of RMS under FIN 46 and that NU is now required to consolidate RMS into NU's financial statements. To consolidate RMS, NU adjusted the carrying value of its preferred stock investment in RMS to the net book value of RMS. This adjustment resulted in a negative $4.7 million after-tax cumulative effect of accounting change. NU's remaining investment in RMS totaled $2.7 million at September 30, 2003. NU has no other VIE's for which NU is defined as the "primary beneficiary." Goodwill Impairment Testing: NU conducts annual goodwill impairment testing as of October 1st. Testing of current goodwill balances commenced in October of 2003. Management does not expect that the completion of the impairment testing in the fourth quarter of 2003 will result in an impairment loss. Pension Plan Accounting: At December 31, 2002, the assets of the NU noncontributory defined benefit plan (Plan) exceeded the accumulated benefit obligation (ABO) by approximately $78 million. The ABO is the obligation for employee service provided to date and does not assume future compensation increases. At September 30, 2003, the estimated fair value of Plan assets exceeded the December 31, 2002 ABO by approximately $220 million. If the ABO, when remeasured next on December 31, 2003, exceeds the fair value of Plan assets at that time, then NU would be required to record an additional minimum pension liability. Other Matters - ------------- Other Commitments and Contingencies: For further information regarding other commitments and contingencies, see Note 4, "Commitments and Contingencies," to the consolidated financial statements. Forward Looking Statements: This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancings, regulatory proceedings, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, and other presently unknown or unforeseen factors. Website: Additional financial information is available through NU's website at www.nu.com. RESULTS OF OPERATIONS - NU CONSOLIDATED The components of significant income statement variances for the third quarter of 2003 and the first nine months of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ------------------------------------ Third Nine Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $640 45% $1,360 35% Operating Expenses: Fuel, purchased and net interchange power 595 70 1,204 55 Other operation 40 22 64 11 Maintenance (13) (18) (24) (12) Depreciation - - (6) (4) Amortization (5) (9) 48 56 Amortization of rate reduction bonds 5 15 (1) (1) Taxes other than income taxes 6 12 2 1 ---- ---- ------ ---- Total operating expenses 628 48 1,287 37 ---- ---- ------ ---- Operating income 12 10 73 22 ---- ---- ------ ---- Interest expense, net (4) (6) (17) (8) Other income/(loss), net (27) (85) (14) (70) ---- ---- ------ ---- Income before income tax expense (11) (14) 76 53 Income tax expense (7) (21) 41 97 Preferred dividends of subsidiaries - - - - ---- ---- ------ ---- Income before cumulative effect of accounting change (4) (9) 35 36 Cumulative effect of accounting change, net of tax benefit of $2,553 (5) (100) (5) (100) ---- ---- ------ ---- Net Income $ (9) (19)% $ 30 31% ==== ==== ====== ==== Comparison of the Third Quarter of 2003 to the Third Quarter of 2002 Operating Revenues Total revenues increased $640 million or 45 percent in the third quarter of 2003, compared with the same period in 2002, due to higher revenues from NU Enterprises ($611 million after intercompany eliminations) and higher Utility Group revenues ($29 million after intercompany eliminations). NU Enterprises' revenue increase is primarily due to higher wholesale revenues for Select Energy resulting from higher short-term sales. The Utility Group revenue increase is primarily due to higher retail revenue ($121 million), partially offset by lower wholesale revenue ($88 million). The regulated retail revenue increase is primarily due to CL&P's recovery of incremental LMP costs ($69 million), increased electric sales volumes ($44 million) including a positive adjustment in estimated unbilled revenue and higher price mix among customer classes ($11 million), partially offset by lower revenues for Yankee ($4 million) primarily due to a downward adjustment in estimated unbilled revenues. The total revenue impact of the unbilled revenues adjustment was a positive $28 million. Regulated retail electric kWh sales increased by 4.9 percent in the third quarter of 2003 after reflecting adjustments to unbilled revenues. The regulated wholesale revenue decrease is primarily due to lower PSNH sales as a result of owning less generation due to the sale of Seabrook. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $595 million or 70 percent in the third quarter of 2003, primarily due to higher wholesale energy purchases at NU Enterprises ($634 million after intercompany eliminations), partially offset by lower purchased-power costs for the Utility Group ($35 million after intercompany eliminations). Other Operation Other operation expense increased $40 million primarily due to higher competitive business cost of goods sold expenses and higher expenses resulting from business growth ($35 million), higher regulated business administrative and general expenses ($6 million), primarily due to higher health care costs and lower pension income, and higher RMR related transmission expense ($3 million), partially offset by lower nuclear expense resulting from the sale of Seabrook ($7 million). Maintenance Maintenance expense decreased $13 million primarily due to lower transmission expenses at NU Enterprises ($6 million), lower regulated electric distribution expenses primarily due to lower storm related expenses ($3 million), and lower nuclear expense due to the 2002 sale of Seabrook ($2 million). Amortization Amortization decreased $5 million in 2003, primarily due to lower recovery of stranded costs by the Utility Group. Amortization of Rate Reduction Bonds Amortization of rate reduction bonds increased $5 million due to an increase in the scheduled payment of principal. Taxes Other Than Income Taxes Taxes other than income taxes increased $6 million in the third quarter of 2003 primarily due to the recognition in 2002 of a Connecticut sales and use tax audit settlement ($8 million), partially offset by a payment in 2002 to compensate the Town of Waterford for lost property tax revenue as a result of the sale of Millstone in 2001 ($3 million). Interest Expense, Net Interest expense, net decreased $4 million primarily due to lower interest at NU parent and CL&P resulting from lower rates ($4 million) and lower North Atlantic Energy Corporation (NAEC) interest due to the retirement of debt ($1 million), partially offset by higher competitive business interest as a result of higher debt levels ($2 million). Other Income/(Loss), Net Other income/(loss), net decreased $27 million primarily due to the third quarter 2002 elimination of certain reserves associated with NU's ownership share of Seabrook ($25 million). Income Tax Expense Income tax expense decreased $7 million primarily due to lower taxable income. Cumulative Effect of Accounting Change, Net of Tax Benefit The cumulative effect of accounting change, net of tax benefit was recorded in the third quarter of 2003 in connection with the adoption of FIN 46, effective July 1, 2003, which required NU to consolidate RMS into NU's financial statements and adjusted its equity interest as a cumulative effect of an accounting change. Comparison of the First Nine Months of 2003 to the First Nine Months of 2002 Operating Revenues Total revenues increased $1.4 billion or 35 percent in the first nine months of 2003, compared with the same period in 2002, due to higher revenues from NU Enterprises ($1.1 billion after intercompany eliminations) and higher Utility Group revenues ($234 million after intercompany eliminations). NU Enterprises' revenue increase is primarily due to higher wholesale revenues for Select Energy resulting from the New Jersey basic generation service and higher short-term sales. The Utility Group revenue increase is primarily due to higher retail revenue ($311 million), partially offset by lower wholesale revenue ($72 million). The regulated retail revenue increase is primarily due to higher retail electric sales volumes ($121 million), higher CL&P recovery of incremental LMP costs ($99 million), higher Yankee Gas revenue resulting from higher purchased gas adjustment clause revenue ($47 million) and higher gas sales volumes ($22 million), and higher price mix among customer classes for the regulated companies ($19 million). Regulated retail electric kWh sales increased by 4.9 percent and firm natural gas sales increased by 3.1 percent in 2003, both after the adjustments to unbilled revenues. The regulated wholesale revenue decrease is primarily due to lower PSNH 2003 sales as a result of the sale of Seabrook. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $1.2 billion or 55 percent in 2003, primarily due to higher wholesale energy purchases at NU Enterprises ($1.2 billion after intercompany eliminations) and higher purchased-power costs for the Utility Group ($33 million after intercompany eliminations). Other Operation Other operation expense increased $64 million primarily due to higher competitive business expenses resulting from business growth ($43 million), higher RMR related transmission expense ($17 million), higher conservation and load management expenditures ($14 million), and higher regulated business administrative and general expenses ($11 million), primarily due to higher health care costs and lower pension income, partially offset by lower nuclear expense due to the sale of Seabrook ($27 million). Maintenance Maintenance expense decreased $24 million primarily due to lower nuclear expense resulting from the sale of Seabrook ($24 million) and lower competitive transmission expenses ($6 million), partially offset by higher fossil production expenses resulting from PSNH generation maintenance overhauls ($5 million). Depreciation Depreciation decreased $6 million in 2003 primarily due to lower decommissioning and depreciation expenses resulting from 2002 depreciation of Seabrook as compared to no 2003 depreciation ($8 million) and lower NU Enterprises depreciation due to a study which resulted in lengthening the useful lives of certain generation assets ($3 million), partially offset by higher Utility Group depreciation resulting from higher plant balances. Amortization Amortization increased $48 million in 2003 primarily due to higher amortization related to the Utility Group's recovery of stranded costs, in part resulting from higher wholesale revenue from the sale of independent power producer related energy. Amortization of Rate Reduction Bonds Amortization of rate reduction bonds decreased $1 million due to the scheduled payment of principal. Taxes Other Than Income Taxes Taxes other than income taxes increased $2 million primarily due to the recognition in 2002 of a Connecticut sales and use tax audit settlement ($8 million), partially offset by a payment in 2002 to compensate the Town of Waterford for lost property tax revenue as a result of the sale of Millstone ($3 million) and lower New Hampshire property taxes due to the sale of Seabrook ($2 million). Interest Expense, Net Interest expense, net decreased $17 million primarily due to lower interest for the regulated subsidiaries resulting from lower rates ($10 million), lower interest at NU parent as a result of the interest rate swap related to its $263 million fixed-rate senior notes ($7 million) and lower NAEC interest due to the retirement of debt ($3 million), partially offset by higher competitive business interest as a result of higher debt levels ($4 million). Other Income/(Loss), Net Other income/(loss), net decreased $14 million primarily due to the third quarter 2002 elimination of certain reserves associated with NU's ownership share of Seabrook ($25 million), partially offset by a charge in the first quarter of 2002 reflecting a write-down of NU's investments in NEON and Acumentrics ($15 million). Income Tax Expense Income tax expense increased $41 million due to higher taxable income and the recording in 2002 of WMECO investment tax credits resulting from a regulatory decision ($13 million). Cumulative Effect of Accounting Change, Net of Tax Benefit The cumulative effect of accounting change, net of tax benefit was recorded in the third quarter of 2003 in connection with the adoption of FIN 46 which required NU to consolidate RMS into NU's financial statements and adjust its equity interest as a cumulative effect of an accounting change. INDEPENDENT ACCOUNTANTS' REPORT To the Board of Trustees and Shareholders of Northeast Utilities: We have reviewed the accompanying condensed consolidated balance sheet of Northeast Utilities and subsidiaries ("the Company") as of September 30, 2003, and the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2003 and 2002, and of cash flows for the nine-month periods ended September 30, 2003 and 2002. These interim financial statements are the responsibility of the Company's management. We conducted our reviews in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and of making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheets and consolidated statements of capitalization of Northeast Utilities and subsidiaries as of December 31, 2002 and 2001, and the related consolidated statements of income, comprehensive income, shareholders' equity, cash flows, and income taxes for the years then ended (not presented herein) and in our report dated January 28, 2003 (February 27, 2003 as to Note 8A), we expressed an unqualified opinion (which includes explanatory paragraphs with respect to the Company's adoption in 2001 of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended and its adoption in 2002 of Emerging Issues Task Force Issue 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" and SFAS No. 142 "Goodwill and Other Intangible Assets") on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2002 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Hartford, Connecticut November 7, 2003 Northeast Utilities and Subsidiaries The Connecticut Light and Power Company and Subsidiaries Public Service Company of New Hampshire and Subsidiaries Western Massachusetts Electric Company and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (All Companies) A. Presentation The accompanying unaudited financial statements should be read in conjunction with this complete report on Form 10-Q, the first and second quarter 2003 reports on Form 10-Q, the Annual Reports of Northeast Utilities (NU or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), which were filed as part of the NU 2002 Form 10-K, and the current report on Form 8-K dated September 30, 2003. The accompanying financial statements contain, in the opinion of management, all adjustments necessary to present fairly NU's and each NU company's financial position at September 30, 2003, the results of operations for the three-month and nine-month periods ended September 30, 2003 and 2002, and statements of cash flows for the nine-month periods ended September 30, 2003 and 2002. All adjustments are of a normal, recurring nature except those described in Note 1C. Due primarily to the seasonality of NU's business, the results of operations and statements of cash flows for the nine-month periods ended September 30, 2003 and 2002, are not indicative of the results expected for a full year. The consolidated financial statements of NU and of its subsidiaries, as applicable, include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications of prior period data have been made to conform with the current period presentation. Reclassifications were made to regulatory asset and liability amounts and special deposits on the accompanying consolidated balance sheets. Reclassifications have also been made to the accompanying consolidated statements of cash flows. B. Regulatory Accounting The accounting policies of NU's Utility Group conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." The transmission and distribution businesses of CL&P, PSNH and WMECO, along with PSNH's generation business and Yankee Gas Services Company's (Yankee Gas) distribution business, continue to be cost-of-service rate regulated, and management believes that the application of SFAS No. 71 to that portion of those businesses continues to be appropriate. Management also believes that it is probable that NU's operating companies will recover their investments in long-lived assets, including regulatory assets. In addition, all material regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity. The components of regulatory assets are as follows: - ------------------------------------------------------------------------------- At September 30, 2003 - ------------------------------------------------------------------------------- (Millions of Dollars) NU Consolidated CL&P PSNH WMECO - ------------------------------------------------------------------------------- Recoverable nuclear costs $ 134.1 $ 65.9 $ 34.2 $ 34.0 Securitized assets 1,763.2 1,152.7 475.9 134.6 Income taxes, net 277.6 176.5 42.1 49.8 Unrecovered contractual obligations 224.4 111.1 55.5 57.8 Recoverable energy costs 305.0 65.1 224.1 3.8 Other 243.4 91.0 140.2 (38.2) - ------------------------------------------------------------------------------- Totals $2,947.7 $1,662.3 $972.0 $241.8 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- At December 31, 2002 - ------------------------------------------------------------------------------- (Millions of Dollars) NU Consolidated CL&P PSNH WMECO - ------------------------------------------------------------------------------- Recoverable nuclear costs $ 85.4 $ 10.6 $ 36.8 $ 38.0 Securitized assets 1,891.8 1,244.5 505.4 141.9 Income taxes, net 331.9 170.5 96.5 54.2 Unrecovered contractual obligations 239.3 116.8 58.7 63.8 Recoverable energy costs 299.6 49.3 241.7 4.3 Other 228.1 111.0 87.0 (18.5) - ------------------------------------------------------------------------------- Totals $3,076.1 $1,702.7 $1,026.1 $283.7 - ------------------------------------------------------------------------------- At September 30, 2003 and December 31, 2002, the Utility Group also maintained $71.6 million and $63.6 million, respectively, of additional other regulatory assets primarily associated with Yankee Gas. Additionally, the Utility Group maintained $622.3 million and $383.1 million of regulatory liabilities at September 30, 2003 and December 31, 2002, respectively, primarily associated with CL&P's Competitive Transition Assessment (CTA), Generation Service Charge and System Benefits Charge (SBC) and PSNH's Stranded Cost Recovery Charge (SCRC). These amounts are included in deferred credits and other liabilities - other on the accompanying consolidated balance sheets. Regulatory liabilities by Utility Group company are as follows: - ------------------------------------------------------------------------------- At September 30, 2003 - ------------------------------------------------------------------------------- (Millions of Dollars) NU Consolidated CL&P PSNH WMECO - ------------------------------------------------------------------------------- Overrecoveries $622.3 $401.8 $178.2 $2.0 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- At December 31, 2002 - ------------------------------------------------------------------------------- (Millions of Dollars) NU Consolidated CL&P PSNH WMECO - ------------------------------------------------------------------------------- Overrecoveries $383.1 $189.7 $187.1 $0.5 - ------------------------------------------------------------------------------- At September 30, 2003 and December 31, 2002, the Utility Group also maintained $40.3 million and $5.8 million, respectively, of additional other regulatory liabilities, primarily held by Yankee Gas. C. New Accounting Standards Derivative Accounting: Effective January 1, 2001, NU adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. In April 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amends SFAS No. 133. This new statement incorporates interpretations that were included in previous Derivative Implementation Group (DIG) guidance, clarifies certain conditions, and amends other existing pronouncements. It is effective for contracts entered into or modified after June 30, 2003. The new rules indicate that derivative contracts that are subject to unplanned netting and can be settled for cash versus delivery would no longer qualify for the normal purchases and sales exception, which would require fair value accounting. Management has determined that the adoption of SFAS No. 149 did not change NU's accounting for wholesale and retail marketing contracts that were entered into prior to July 1, 2003, or the ability of NU to elect the normal purchases and sales exception. Emerging Issues Task Force (EITF) Issue No. 03-11, "Reporting Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, and 'Not Held for Trading Purposes' as Defined in EITF Issue No. 02-3, 'Issues related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities'" was derived from EITF Issue No. 02-3, which requires net reporting in the income statement in revenues of energy trading activities. Issue No. 03-11 addresses income statement classification of derivatives that are not related to energy trading activities. Prior to Issue No. 03-11, there was no specific accounting guidance that addressed the classification in the income statement of Select Energy, Inc.'s (Select Energy) retail marketing and wholesale contracts, many of which are derivatives. The only applicable guidance was EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent." The indicators of gross revenue reporting include whether the entity is the primary obligor in the arrangement, whether the entity has inventory or credit risk, latitude in establishing price, and discretion in supplier selection. Indicators of net revenue reporting are whether the supplier is the primary obligor in the arrangement, the entity earns a fixed amount and the supplier has credit risk. On July 31, 2003, the EITF reached a consensus in Issue No. 03-11 that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on the relevant facts and circumstances. The EITF indicated that the indicators set forth in Issue No. 99-19 should continue to be considered and provided no new accounting guidance. Additionally, the consensus recommends disclosure of where the gains and losses are recorded in the income statement, and whether they are presented on a net or gross basis. Issue No. 03-11 is effective for NU prospectively on October 1, 2003. Select Energy currently reports the settlement of short-term and long-term derivative contracts that are not held for trading purposes on a gross basis, generally with sales in revenues and purchases in expenses. Short-term sales and purchases represent power that is purchased to serve full requirements contracts but is ultimately not needed based on the actual load of the full requirements customers. This excess power is sold to the independent system operator or to other counterparties. Management is currently evaluating the impact of the consensus in Issue No. 03- 11 as it relates to income statement classification of Select Energy's short-term energy purchases and sales. Management will complete this evaluation in the fourth quarter in accordance with Issue No. 03-11. If management determines that revenues and expenses related to short-term sales and purchases should be reported net, then there could be a significant reduction in both Select Energy's revenues and expenses with no operating income or net income impact. For the first nine months of 2003, short-term and non-requirements sales amounted to approximately $600 million. On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning of "not clearly and closely related regarding contracts with a price adjustment feature" as it relates to the election of the normal purchase and sales exception to derivative accounting. The implementation of this guidance is required for the fourth quarter of 2003 for NU. Management is currently evaluating the impacts of Issue No. C-20, but believes that when it is implemented, Issue No. C-20 will likely result in CL&P recording the fair value of two existing power purchase contracts as derivative liabilities with offsetting regulatory assets, as these contracts are part of stranded costs and as management believes that these costs will continue to be recovered in rates. Management's preliminary estimates of the fair values of these long- term power purchase contracts indicate that the contracts have a combined negative fair value of approximately $16 million. Accounting for RMS Variable Interest Entity: On June 30, 2001, NU sold R. M. Services, Inc. (RMS) for $10 million in the form of convertible cumulative 5 percent preferred stock and a warrant to buy 25 percent of the outstanding common stock of RMS for $1,000 expiring in 2021. NU also agreed to guarantee a $3 million line of credit for RMS through 2005. In the second and third quarters of 2003, RMS has been drawing on this line of credit. In January 2003, the FASB issued Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities," which was effective for NU on July 1, 2003. NU did not electively delay implementation until December 31, 2003. RMS is a variable interest entity (VIE), as defined. FIN 46 requires that the party to a VIE that absorbs the majority of the VIE's losses, defined as the "primary beneficiary," consolidate the VIE. Upon adoption of FIN 46, management determined that NU was the "primary beneficiary" of RMS under FIN 46 and that NU is now required to consolidate RMS into NU's financial statements. To consolidate RMS, NU adjusted the carrying value of its preferred stock investment in RMS to the net book value of RMS. This adjustment resulted in a negative $4.7 million after-tax cumulative effect of accounting change. NU's remaining investment in RMS totaled $2.7 million at September 30, 2003. NU has no other VIE's for which NU is defined as the "primary beneficiary." Liabilities and Equity: In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes standards on how to classify and measure certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise effective for NU for the third quarter of 2003. As NU no longer has any preferred stock subject to mandatory redemption outstanding, the adoption of SFAS No. 150 did not have an impact on NU's consolidated financial statements. D. Stock-Based Compensation NU maintains an Employee Stock Purchase Plan and other long-term, stock-based incentive plans under the Northeast Utilities Incentive Plan (Incentive Plan). NU accounts for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations. No stock-based employee compensation cost for stock options is reflected in net income, as all options granted under those plans had an exercise price equal to or above the market value of the underlying common stock on the date of grant. At this time, NU has not elected to transition to expensing stock options under the fair value-based method of accounting for stock-based employee compensation. The following tables illustrate the effect on net income and earnings per share (EPS) if NU had applied the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation related to stock options and NU's Employee Stock Purchase Plan: --------------------------------------------------------------------- For the Three Months Ended --------------------------------------------------------------------- (Millions of Dollars, September 30, September 30, except per share amounts) 2003 2002 --------------------------------------------------------------------- Net income, as reported $39.2 $48.6 Total stock-based employee compensation expense determined under fair value-based method for all awards, net of related (0.6) (1.1) tax effects --------------------------------------------------------------------- Pro forma net income $38.6 $47.5 --------------------------------------------------------------------- EPS: Basic and fully Diluted - as reported $ 0.31 $ 0.38 Basic and fully Diluted - pro forma $ 0.30 $ 0.37 --------------------------------------------------------------------- --------------------------------------------------------------------- For the Nine Months Ended --------------------------------------------------------------------- (Millions of Dollars, September 30, September 30, except per share amounts) 2003 2002 --------------------------------------------------------------------- Net income, as reported $126.3 $96.1 Total stock-based employee compensation expense determined under fair value-based method for all awards, net of related (1.8) (3.4) tax effects --------------------------------------------------------------------- Pro forma net income $124.5 $92.7 --------------------------------------------------------------------- EPS: Basic and fully diluted - as reported $ 0.99 $ 0.74 Basic and fully diluted - pro forma $ 0.98 $ 0.71 --------------------------------------------------------------------- During the nine-month period ended September 30, 2003, NU granted approximately 384,000 shares of restricted stock under the Incentive Plan. The shares granted had a value of $5.4 million when granted. This amount was recorded in shareholders' equity. For the nine months ended September 30, 2003, approximately $1.2 million was amortized to expense related to the restricted stock. During the nine-month period ended September 30, 2003, no stock options were awarded. E. Other Income/(Loss), Net The pre-tax components of NU's other income/(loss), net items are as follows: --------------------------------------------------------------------- For the Nine Months Ended --------------------------------------------------------------------- September 30, September 30, (Millions of Dollars) 2003 2002 --------------------------------------------------------------------- Investment write-downs $ - $(17.1) Seabrook-related items - 23.3 Investment income 13.5 19.1 Other, net (7.5) (5.6) --------------------------------------------------------------------- Totals $ 6.0 $ 19.7 --------------------------------------------------------------------- F. Sale of Customer Receivables CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. At September 30, 2003, CL&P had sold accounts receivable of $40 million to the financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. Additionally, at September 30, 2003, $6.4 million of assets were designated as collateral and restricted under the agreement with CRC. Concentrations of credit risk to the purchaser under this agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. At September 30, 2003, amounts sold to CRC from CL&P but not sold to the financial institution totaling $215.6 million are included in investments in securitizable assets on the accompanying consolidated balance sheets. These amounts would be excluded from CL&P's assets in the event of CL&P's bankruptcy. At December 31, 2002, $40 million of accounts receivable were sold to the financial institution. On July 9, 2003, CL&P renewed this arrangement for a one-year period. G. Guarantees In November 2002, the FASB issued FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," which requires disclosures by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued and clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. NU provides credit assurance in the form of guarantees and letters of credit in the normal course of business, primarily for the financial performance obligations of NU Enterprises. NU would be required to perform under these guarantees in the event of non- performance by NU Enterprises, primarily Select Energy. At September 30, 2003, the maximum level of exposure under guarantees by NU, primarily on behalf of NU Enterprises, totaled approximately $435 million. Additionally, NU had $123.2 million of letters of credit issued for the benefit of NU Enterprises outstanding at September 30, 2003. In conjunction with its investment in RMS, NU guarantees a $3 million line of credit through 2005, of which $0.5 million was outstanding at September 30, 2003, which is included in the $435 million total. Effective July 1, 2003, NU now consolidates the financial statements of RMS with the NU financial statements. Additionally, CL&P has obtained surety bonds in the amount of $31.1 million related to the March 2003 and April 2003 incremental locational marginal pricing (LMP) costs to comply with a Connecticut Department of Public Utility Control (DPUC) order. At September 30, 2003, NU guaranteed $42.8 million of surety bonds for NU subsidiaries, including the LMP-related surety bonds. This amount is included in the total NU guarantee amount of approximately $435 million. These surety bonds contain ratings triggers that would require NU to post additional collateral in the event that NU's ratings are downgraded. NU currently has authorization from the Securities and Exchange Commission (SEC) to provide up to $500 million of guarantees for NU Enterprises through June 30, 2004, and has applied for authority to increase this amount to $750 million through September 30, 2006. The aforementioned surety bonds are subject to a separate $50 million SEC limitation apart from the current $500 million guarantee limit. The amount of guarantees outstanding for compliance with the SEC limit is approximately $258 million, which is calculated using different criteria than the maximum level of exposure of approximately $435 million required to be disclosed under FIN 45. The $42.8 million of surety bonds is the same for both SEC and FIN 45 purposes. H. Adjustments to Estimates of Unbilled Revenues Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not been billed. Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed. Billed revenues are based on meter readings. Unbilled revenues are estimated monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity or gas delivered to the system and applies a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses to calculate the total estimated monthly sales to customers. The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales. In the third quarter of 2003, the unbilled sales estimates for all Utility Group companies were tested using the cycle method and will be tested annually hereafter. The cycle method is historically more accurate than the requirements method, when used in a mostly weather-neutral month. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method resulted in an adjustment to the estimate of unbilled revenues that had a net positive after-tax earnings impact of approximately $5.7 million in the third quarter of 2003. The positive after-tax impacts on CL&P, PSNH, and WMECO were $7.2 million, $3.3 million, and $0.3 million, respectively. There was a negative after-tax impact on Yankee Gas of $5.1 million. I. Restricted Cash - LMP Costs and Special Deposits Restricted cash - LMP costs represents incremental LMP cost amounts that have been collected by CL&P and deposited into an escrow account. Special deposits primarily consist of collateral balances resulting from Select Energy wholesale activities. 2. DERIVATIVE INSTRUMENTS, MARKET RISK AND RISK MANAGEMENT (NU, Select Energy, Yankee Gas) A. Derivative Instruments Effective January 1, 2001, NU adopted SFAS No. 133, as amended by SFAS No. 149 in April 2003. Derivatives that are utilized for trading purposes are recorded at fair value with changes in fair value included in net income. Other contracts that are derivatives but do not meet the definition of a cash flow hedge and cannot be designated as being used for normal purchases or normal sales are also recorded at fair value with changes in fair value included in net income. For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, the changes in the fair value of the effective portion of those contracts are generally recognized in accumulated other comprehensive income, a component of equity, until the underlying transactions occur. For those contracts that meet the definition of a derivative and meet the fair value hedge requirements, the changes in fair value of the effective portion of those contracts are generally recognized on the balance sheet as both the hedge and the hedged item are recorded at fair value. For contracts that meet the definition of a derivative but do not meet the hedging requirements, and for the ineffective portion of contracts that meet the cash flow hedge requirements, the changes in fair value of those contracts are recognized currently in net income. Derivative contracts that are entered into as a normal purchase or sale, will result in physical delivery, meet the definitions in SFAS No. 149, and are documented as such, are recorded under accrual accounting. For information regarding recent accounting changes related to trading activities, see Note 1C, "New Accounting Standards," to the consolidated financial statements. During the first nine months of 2003, a negative $7.8 million, net of tax, was reclassified from other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized in net income. The related hedged transactions were also recognized in net income. A negative $0.02 million, net of tax, was recognized in net income for those derivatives that were determined to be ineffective and for the ineffective portion of cash flow hedges. Also during the third quarter of 2003, new cash flow hedge transactions were entered into that hedge cash flows through 2005. As a result of these new transactions and market value changes since January 1, 2003, other comprehensive income decreased by $18.7 million, net of tax. Accumulated other comprehensive income at September 30, 2003, was a negative $3.2 million, net of tax (decrease to equity), relating to hedged transactions, and it is estimated that negative $1.6 million of this balance, net of tax, will be reclassified as an increase to net income within the next twelve months. Cash flows from the hedge contracts are reported in the same category as cash flows from the underlying hedged transaction. The tables below summarize the derivative assets and liabilities at September 30, 2003 and December 31, 2002. These amounts do not include premiums paid, which are recorded as prepayments and amounted to $18.6 million and $26.7 million at September 30, 2003 and December 31, 2002, respectively. These amounts also do not include premiums received, which are recorded as other current liabilities and amounted to $15.8 million and $33.9 million at September 30, 2003 and December 31, 2002, respectively. The premium amounts relate primarily to energy trading activities. --------------------------------------------------------------------- At September 30, 2003 --------------------------------------------------------------------- (Millions of Dollars) Assets Liabilities Total --------------------------------------------------------------------- Select Energy: Trading $ 89.0 $(52.8) $36.2 Nontrading 3.6 (1.4) 2.2 Hedging 7.3 (11.7) (4.4) --------------------------------------------------------------------- Yankee Gas: Hedging 2.3 - 2.3 --------------------------------------------------------------------- NU Parent: Hedging 1.6 - 1.6 --------------------------------------------------------------------- Total $103.8 $(65.9) $37.9 --------------------------------------------------------------------- --------------------------------------------------------------------- At December 31, 2002 --------------------------------------------------------------------- (Millions of Dollars) Assets Liabilities Total --------------------------------------------------------------------- Select Energy: Trading $102.9 $(61.9) $41.0 Nontrading 2.9 - 2.9 Hedging 22.8 (2.0) 20.8 --------------------------------------------------------------------- Yankee Gas: Hedging 2.3 - 2.3 --------------------------------------------------------------------- Total $130.9 $(63.9) $67.0 --------------------------------------------------------------------- Select Energy Trading: To gather market intelligence and utilize this information in risk management activities for the wholesale business, Select Energy conducts limited energy trading activities in electricity, natural gas and oil, and therefore, experiences net open positions. Select Energy manages these open positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures. Derivatives used in trading activities are recorded at fair value and included in the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recognized in operating revenues in the consolidated statements of income in the period of change. The net fair value positions of the trading portfolio at September 30, 2003 and December 31, 2002 were assets of $36.2 million and $41 million, respectively. Select Energy's trading portfolio includes New York Mercantile Exchange (NYMEX) futures and options, the fair value of which is based on closing exchange prices; over-the-counter forwards and options, the fair value of which is based on the mid-point of bid and ask market prices; bilateral contracts for the purchase or sale of electricity or natural gas, the fair value of which is determined using available information from external sources; and a long-term bilateral energy purchase contract, the fair value of which is determined using a model. The trading portfolio also includes a LIBOR-based interest rate swap to mitigate fair value fluctuations from changes in the LIBOR-based discount rate used to determine the fair value of certain trading contracts. Select Energy's trading portfolio also includes transmission congestion contracts. The fair value of certain transmission congestion contracts is based on published market data. Market information for other transmission congestion contracts is not available, and those contracts cannot be reliably valued. Management believes the amounts paid for these contracts, which total $4.6 million, are equal to their fair value. Select Energy Nontrading: Nontrading derivative contracts are used for delivery of energy related to Select Energy's retail and wholesale activities. These contracts are not entered into for trading purposes, but are subject to fair value accounting because these contracts are derivatives that cannot be designated as normal purchases or sales, as defined. These contracts cannot be designated as normal purchases or sales either because they are included in the New York energy market that settles financially or because the normal purchase and sale designation was not elected by management. The net fair values of nontrading derivatives valued at the mid-point of bid and ask market prices at September 30, 2003 and December 31, 2002 were assets of $2.2 million and $2.9 million, respectively. Select Energy Hedging: Select Energy utilizes derivative financial and commodity instruments, including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas purchased to meet firm sales commitments to certain customers. Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts, to manage the market risk associated with a portion of its anticipated retail supply requirements. These derivatives have been designated as cash flow hedging instruments and are used to reduce the market risk associated with fluctuations in the price of electricity, natural gas, or oil. A derivative that hedges exposure to the variable cash flows of a forecasted transaction (a cash flow hedge) is initially recorded at fair value with changes in fair value recorded in accumulated other comprehensive income. Hedges impact net income when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis. Select Energy maintains natural gas service agreements with certain customers to supply gas at fixed prices for terms extending through 2005. Select Energy has hedged its gas supply component of the risk under these agreements through NYMEX futures contracts. Under these contracts, which also extend through 2005, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements. At September 30, 2003, the NYMEX futures contracts had notional values of $81.9 million and were recorded at fair value as a derivative liability of $1.7 million. Other derivative liabilities, which are valued at the mid-point of bid and ask market prices, include forwards, options and swaps to hedge Select Energy's basic generation service contracts in the PJM region and were recorded at fair value as derivative liabilities of $5 million. Other derivative liabilities include futures, options and swaps in the New England region, which were recorded as derivative liabilities with a fair value of $4.2 million at September 30, 2003. SENY maintains hedges on its retail sales portfolio through 2004, which were also valued at the mid-point of bid and ask market prices and recorded at fair value as a derivative asset of $4.1 million at September 30, 2003. Yankee Gas Hedging: Yankee Gas maintains a master swap agreement with a financial counterparty to purchase gas at fixed prices. Under this master swap agreement, the purchase price of a specified quantity of gas for an unaffiliated customer is effectively fixed over the term of the gas service agreement with that customer for a period of time not extending beyond 2005. At September 30, 2003, the commodity swap agreement had a notional value of $7.2 million and was recorded at fair value as a derivative asset of $2.3 million with an offsetting fair value of the firm commitment recorded in current liabilities in the accompanying consolidated balance sheets. NU Parent Hedging: In March of 2003, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed-rate note that matures on April 1, 2012. As a perfectly matched fair value hedge, the changes in fair value of the swap and the hedged debt instrument are recorded on the balance sheet but are equal and offsetting in the consolidated statements of income. The cumulative change in the fair value of the hedged debt of $1.6 million is included as long-term debt on the consolidated balance sheets. Additionally, the resulting changes in interest payments made are recorded as adjustments to interest expense. B. Market Risk Information Select Energy utilizes the sensitivity analysis methodology to disclose quantitative information for its commodity price risks. Sensitivity analysis provides a presentation of the potential loss of future net income, fair values or cash flows from market risk- sensitive instruments over a selected time period due to one or more hypothetical changes in commodity prices, or other similar price changes. Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity, contract prices and market prices represented by each derivative commodity contract. For swaps, forward contracts and options, fair value reflects management's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recorded at fair value based on closing exchange prices. Select Energy Trading Portfolio: At September 30, 2003, Select Energy calculated the market price resulting from a 10 percent change in forward market prices. That 10 percent change would result in approximately a $0.3 million increase or decrease in the fair value of the Select Energy trading portfolio. In the normal course of business, Select Energy also faces risks that are either nonfinancial or nonquantifiable. Such risks principally include credit risk, which is not reflected in this sensitivity analysis. Select Energy Retail Marketing and Wholesale Portfolio: When conducting sensitivity analyses of the change in the fair value of Select Energy's electricity, natural gas and oil nontrading derivatives portfolio, which would result from a hypothetical change in the future market price of electricity, natural gas and oil, the fair values of the contracts are determined from models that take into account estimated future market prices of electricity, natural gas and oil, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments. In most instances, market prices and volatility are determined from quotes on the futures exchange. Select Energy has determined a hypothetical change in the fair value for its retail marketing and wholesale portfolio, which includes cash flow hedges and electricity, natural gas and oil contracts and generation assets, assuming a 10 percent change in forward market prices. At September 30, 2003, a 10 percent change in market price would have resulted in an increase or decrease in fair value of approximately $3.5 million. The impact of a change in electricity, natural gas and oil prices on Select Energy's retail marketing and wholesale portfolio at September 30, 2003, is not necessarily representative of the results that will be realized when the commodities provided for in these contracts are physically delivered. C. Other Risk Management Activities Interest Rate Risk Management: NU manages its interest rate risk exposure in accordance with written policies and procedures by maintaining a mix of fixed and variable rate debt. At September 30, 2003, approximately 80 percent (70 percent including the debt subject to the fixed to floating interest rate swap in variable rate debt), of NU's long-term debt, including fees and interest due for spent nuclear fuel disposal costs, is at a fixed interest rate. The remaining long-term debt is variable-rate and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in NU's variable interest rates, including the rate on debt subject to the fixed to floating interest rate swap, annual interest expense would have increased by $7.6 million. At September 30, 2003, NU parent maintained a fixed to floating interest rate swap to manage the risk associated with its $263 million of fixed-rate debt. Credit Risk Management: Credit risk relates to the risk of loss that NU would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. NU serves a wide variety of customers and suppliers that include independent power producers, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and NU realizes interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms which, in turn, requires NU to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by NU's risk management process. NU's Utility Group has a lower level of credit risk related to providing electric and gas distribution service than NU Enterprises. Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council operating outside of the business units that create or actively manage these risk exposures to ensure compliance with NU's stated risk management policies. NU tracks and re-balances the risk in its portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure. NYMEX traded futures and option contracts are guaranteed by the NYMEX and have a lower credit risk. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require an evaluation of potential counterparties' financial conditions (including credit ratings), collateral requirements under certain circumstances (including cash in advance, letters of credit, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to NU entering into trading activities. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact NU's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. At September 30, 2003, Select Energy maintained collateral balances from counterparties of $29.2 million. This amount is included in both special deposits and other current liabilities on the accompanying consolidated balance sheets. 3. GOODWILL AND OTHER INTANGIBLE ASSETS Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other Intangible Assets," which ended the amortization of goodwill and certain intangible assets with indefinite useful lives. SFAS No. 142 also required that goodwill and intangible assets deemed to have indefinite useful lives be reviewed for impairment upon adoption of SFAS No. 142 and at least annually thereafter by applying a fair value-based test. NU selected October 1 as the annual goodwill impairment testing date. Under SFAS No. 142, goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount of the goodwill. Excluding adjustments to the purchase price allocation in July 2003 related to the acquisition of Woods Electrical Co., Inc. and Woods Network Services, Inc. (Woods Network), there were no impairments or adjustments to the goodwill balances during the nine-month periods ended September 30, 2003 and 2002. These adjustments primarily related to the recording of contingent payments based on certain earnings targets that have been met, as defined in the purchase agreements. NU's reporting units that maintain goodwill are generally consistent with the operating segments underlying the reportable segments identified in Note 7, "Segment Information," to the consolidated financial statements. Consistent with the way management reviews the operating results of its reporting units, NU's reporting units under the NU Enterprises reportable segment include: 1) the wholesale and retail business reporting unit, and 2) the services reporting unit. The wholesale and retail business reporting unit is comprised of the operations of Select Energy, Northeast Generation Company (NGC) and the ongoing generation operations of Holyoke Water Power Company (HWP), while the services reporting unit is comprised of the operations of Select Energy Services, Inc. (SESI), Northeast Generation Services Company (NGS) and Woods Network. As a result, NU's reporting units that maintain goodwill are as follows: Yankee Gas, classified under the Utility Group - gas reportable segment, the wholesale and retail business reporting unit and the services reporting unit which are both classified under the NU Enterprises reportable segment. The goodwill balances of these reporting units are included in the table herein. At September 30, 2003, NU maintained $319.9 million of goodwill that is no longer being amortized, $15.5 million of identifiable intangible assets and $8.5 million of intangible assets not subject to amortization, totaling $343.9 million. At December 31, 2002, NU maintained $321 million of goodwill that is no longer being amortized, $18.1 million of identifiable intangible assets and $6.8 million of intangible assets not subject to amortization, totaling $345.9 million. These amounts are included on the consolidated balance sheets as goodwill and other purchased intangible assets, net. A summary of NU's goodwill balances at September 30, 2003 and December 31, 2002, by reportable segment and reporting unit is as follows: -------------------------------------------------------------------------- (Millions of Dollars) September 30, 2003 December 31, 2002 -------------------------------------------------------------------------- Utility Group - Gas: Yankee Gas $287.6 $287.6 NU Enterprises: Services 29.1 30.2 Wholesale and Retail Business 3.2 3.2 -------------------------------------------------------------------------- Totals $319.9 $321.0 -------------------------------------------------------------------------- At September 30, 2003 and December 31, 2002, NU's intangible assets and related accumulated amortization consisted of the following: -------------------------------------------------------------------------- At September 30, 2003 -------------------------------------------------------------------------- Gross Accumulated Net (Millions of Dollars) Balance Amortization Balance -------------------------------------------------------------------------- Intangible assets subject to amortization: Exclusivity agreement $17.7 $6.5 $11.2 Customer list 6.6 2.4 4.2 Customer backlog, employment related agreements and other 0.1 - 0.1 -------------------------------------------------------------------------- Totals $24.4 $8.9 $15.5 -------------------------------------------------------------------------- Intangible assets not subject to amortization: Customer relationships $ 5.2 Tradenames 3.3 --------------------------------------------- Totals $ 8.5 --------------------------------------------- -------------------------------------------------------------------------- At December 31, 2002 -------------------------------------------------------------------------- Gross Accumulated Net (Millions of Dollars) Balance Amortization Balance -------------------------------------------------------------------------- Intangible assets subject to amortization: Exclusivity agreement $17.7 $4.6 $13.1 Customer list 6.6 1.7 4.9 Customer backlog, employment related agreements and other 0.1 - 0.1 -------------------------------------------------------------------------- Totals $24.4 $6.3 $18.1 -------------------------------------------------------------------------- Intangible assets not subject to amortization: Customer relationships $ 3.8 Tradenames 3.0 --------------------------------------------- Totals $ 6.8 --------------------------------------------- NU recorded amortization expense of $2.6 million and $1.1 million for the nine months ended September 30, 2003 and 2002, respectively, related to these intangible assets. Based on the current amount of intangible assets subject to amortization, the estimated annual amortization expense for each of the succeeding 5 years from 2004 through 2008 is $3.6 million in 2004 through 2007 and no amortization expense in 2008. These amounts may vary as acquisitions and dispositions occur in the future. 4. COMMITMENTS AND CONTINGENCIES A. Restructuring and Rate Matters (CL&P, PSNH, WMECO) Connecticut: Implementation of Standard Market Design: On March 1, 2003, the New England Independent System Operator (ISO-NE) implemented standard market design (SMD). As part of SMD, LMP is utilized to assign value and causation to transmission congestion and line losses. Management believes that under the legal interpretation of the terms of its standard offer service contracts with its standard offer suppliers, the incremental costs associated with line losses and congestion between the delivery points chosen by the suppliers and CL&P's service territory in Connecticut are the responsibility of CL&P's customers. Management believes that these congestion and line loss charges are unavoidable, are part of the prudent cost of providing regulated electric service in Connecticut and should be paid for by CL&P's customers. CL&P incurred $132.5 million of incremental LMP costs from March 1, 2003 through September 30, 2003. As incurred, these costs were recorded as recoverable energy costs and are included in regulatory assets on the accompanying consolidated balance sheets. CL&P received approval for recovery of these costs through an additional charge on customer bills and began recovering them on May 1, 2003, subject to refund and on a two-month lag. Approximately $95.6 million has been recovered through September 30, 2003. This amount is included in operating revenues and offset by amortization expense. If it is ultimately concluded that the incremental LMP costs are the responsibility of the standard offer service suppliers, NU Enterprises' pre-tax earnings for the nine months ended September 30, 2003 would be reduced by approximately $71 million, and CL&P would eliminate the accounts payable to the standard offer service suppliers with a reduction to operating expenses. At the same time, a regulatory liability in the same amount would be recorded with a reduction to operating revenues. This amount could be material and there would be an impact on NU's and NU Enterprises' net income. Net income could be negatively impacted if LMP recoveries are refunded to CL&P's customers with carrying charges, which would result in interest expenses. CL&P Disposition of Seabrook Proceeds: CL&P sold its share of the Seabrook nuclear unit on November 1, 2002. CL&P received $37 million and recorded a gain on the sale of approximately $16 million. The gain was recorded as a regulatory liability and, when offset by the decommissioning top off and other adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale. This filing described CL&P's treatment of its share of the proceeds from the sale. Hearings in this docket were held in September and a final decision is scheduled to be issued in December 2003. Management does not expect the final decision to have a material effect on CL&P's net income or its financial position. CTA and SBC Reconciliation: On April 3, 2003, CL&P filed its annual CTA and SBC reconciliation with the DPUC. For the year ended December 31, 2002, total CTA revenues and excess Generation Services Charge (GSC) revenues exceeded the CTA revenue requirement by approximately $93.5 million. This amount is recorded as a regulatory liability. CL&P has proposed that a portion of the CTA/GSC overrecovery be utilized to reduce the nuclear stranded cost regulatory asset and that the remaining amount be carried forward through 2003. For the same period, SBC revenues exceeded the SBC revenue requirement by approximately $22.4 million. In compliance with a prior decision of the DPUC, a portion of the SBC overrecovery was applied to regulatory assets, and the remaining overrecovery of $18.6 million was applied to the CTA. Management expects a final decision from the DPUC in this docket by the end of 2003. Management does not expect the final decision to have a material effect on CL&P's net income or its financial position. Massachusetts: On March 31, 2003, WMECO filed its 2002 annual transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE). This filing reconciled the recovery of generation-related stranded costs for calendar year 2002 and included the renegotiated purchased power contract related to the Vermont Yankee nuclear unit. On July 15, 2003, the DTE issued a final order on WMECO's 2001 annual transition cost reconciliation, which addressed WMECO's cost tracking mechanisms. As part of that order, the DTE directed WMECO to revise its 2002 annual transition cost reconciliation filing. The revised filing was submitted to the DTE on September 23, 2003. Hearings were held in October 2003, and a final decision from the DTE is expected in the first half of 2004. Management does not expect the outcome of this docket to have a material adverse impact on WMECO's net income or its financial position. B. NRG Energy, Inc. Exposures (CL&P, Yankee Gas, NGS) Certain subsidiaries of NU, including CL&P, Yankee Gas and NGS, have entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries. On May 14, 2003, NRG and certain of its subsidiaries filed voluntary bankruptcy petitions. NRG-related exposures to NU as a result of these transactions relate to 1) the recovery of CL&P's station service billings from NRG, 2) NRG's standard offer service contract with CL&P, 3) the recovery of congestion charges incurred by NRG prior to the implementation of SMD on March 1, 2003, and 4) the recovery of Yankee Gas', NGS' and CL&P's expenditures that were incurred related to NRG's generating plant construction project that is now abandoned. While it is unable to determine the ultimate outcome of these issues, management does not expect their resolution will have a material adverse effect on NU's consolidated financial condition or results of operations. C. Long-Term Contractual Arrangements (Select Energy) Select Energy maintains long-term agreements to purchase energy in the normal course of business as part of its portfolio of resources to meet its actual or expected sales commitments. The aggregate amount of these purchase contracts was $4.9 billion at September 30, 2003, as follows (millions of dollars): --------------------------------------------------------------------- Year --------------------------------------------------------------------- 2003 $1,412.1 2004 2,345.2 2005 639.2 2006 283.0 2007 225.1 --------------------------------------------------------------------- Total $4,904.6 --------------------------------------------------------------------- Select Energy's purchase contract amounts can exceed the amount expected to be reported in fuel, purchased and net interchange power as energy trading purchases are classified net with the corresponding revenues. D. Deferred Contractual Obligation - Connecticut Yankee Atomic Power Company (CYAPC) Decommissioning Dispute In June 2003, CYAPC notified NU that it had terminated its contract with Bechtel Power Corporation (Bechtel) for the decommissioning of the Connecticut Yankee nuclear power plant. CYAPC terminated the contract based on its determination that Bechtel's decommissioning work has been incomplete and untimely and that Bechtel refused to perform the remaining decommissioning work. NU's electric operating subsidiaries collectively own 49.0 percent of CYAPC; CL&P owns 34.5 percent, PSNH owns 5.0 percent and WMECO owns 9.5 percent. NU has been notified by CYAPC that it is in the process of preparing an update to the estimated cost to decommission Connecticut Yankee. When completed, the new 2003 estimate will reflect the new estimated cost and schedule to complete the decommissioning, including the impacts of the Bechtel contract termination. The new cost estimate is expected to increase significantly from the previous decommissioning estimate that NU received from CYAPC in 2002. CYAPC is seeking recovery of the additional project completion costs and other damages from Bechtel but may ultimately recover these costs through Federal Energy Regulatory Commission (FERC)-approved rates charged to CL&P, PSNH and WMECO. The increase in the CYAPC decommissioning cost estimate will increase deferred contractual obligations. Past increases to deferred contractual obligations have been reflected as regulatory assets by CL&P, PSNH and WMECO for future recovery from retail customers. 5. COMPREHENSIVE INCOME (NU, CL&P, PSNH, WMECO) Total comprehensive income, which includes all comprehensive income items by category, for the three months and nine months ended September 30, 2003 and 2002 is as follows:
- ------------------------------------------------------------------------------------ Three Months Ended September 30, 2003 - ------------------------------------------------------------------------------------ NU (Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other - ------------------------------------------------------------------------------------ Net income/(loss)* $ 39.2 $29.0 $12.6 $5.2 $6.9 $(14.5) - ------------------------------------------------------------------------------------ Comprehensive income items: Qualified cash flow hedging instruments (4.9) - - - (4.9) - Unrealized gains on securities 0.2 - - - - 0.2 - ------------------------------------------------------------------------------------ Net change of comprehensive income items (4.7) - - - (4.9) 0.2 - ------------------------------------------------------------------------------------ Total comprehensive income/(loss) $ 34.5 $29.0 $12.6 $5.2 $2.0 $(14.3) - ------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------ Nine Months Ended September 30, 2003 - ------------------------------------------------------------------------------------ NU (Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other - ------------------------------------------------------------------------------------ Net income/(loss)* $126.3 $59.0 $34.5 $13.9 $24.0 $ (5.1) - ------------------------------------------------------------------------------------ Comprehensive income items: Qualified cash flow hedging instruments (18.7) - - - (14.7) (4.0) Unrealized gains on securities 0.9 0.1 0.1 - - 0.7 - ------------------------------------------------------------------------------------ Net change of comprehensive income items (17.8) 0.1 0.1 - (14.7) (3.3) - ------------------------------------------------------------------------------------ Total comprehensive income/(loss) $108.5 $59.1 $34.6 $13.9 $ 9.3 $ (8.4) - ------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------ Three Months Ended September 30, 2002 - ------------------------------------------------------------------------------------ NU (Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other - ------------------------------------------------------------------------------------ Net income/(loss)* $ 48.6 $27.9 $19.5 $ 4.7 $(9.0) $ 5.5 - ------------------------------------------------------------------------------------ Comprehensive income items: Qualified cash flow hedging instruments 5.5 - - - 5.4 0.1 Unrealized gains on securities (0.8) (0.5) (0.2) (0.1) - - - ------------------------------------------------------------------------------------ Net change of comprehensive income items 4.7 (0.5) (0.2) (0.1) 5.4 0.1 - ------------------------------------------------------------------------------------ Total comprehensive income/(loss) $ 53.3 $27.4 $19.3 $ 4.6 $(3.6) $ 5.6 - ------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------ Nine Months Ended September 30, 2002 - ------------------------------------------------------------------------------------ NU (Millions of Dollars) NU CL&P PSNH WMECO Enterprises Other - ------------------------------------------------------------------------------------ Net income/(loss)* $ 96.1 $58.2 $46.4 $26.9 $(38.7) $ 3.3 - ------------------------------------------------------------------------------------ Comprehensive income items: Qualified cash flow hedging instruments 43.7 - - - 38.0 5.7 Unrealized gains on securities (1.2) (0.5) (0.6) (0.1) - - - ------------------------------------------------------------------------------------ Net change of comprehensive income items 42.5 (0.5) (0.6) (0.1) 38.0 5.7 - ------------------------------------------------------------------------------------ Total comprehensive income/(loss) $138.6 $57.7 $45.8 $26.8 $ (0.7) $ 9.0 - ------------------------------------------------------------------------------------
*Net income/(loss) after preferred dividends of subsidiaries. Amounts included in the Other column primarily relate to NU parent, Yankee Gas and Northeast Utilities Service Company. Accumulated other comprehensive income fair value adjustments of NU's qualified cash flow hedging instruments are as follows: -------------------------------------------------------------------------- September 30, December 31, (Millions of Dollars, Net of Tax) 2003 2002 -------------------------------------------------------------------------- Balance at beginning of period $15.5 $(36.9) -------------------------------------------------------------------------- Hedged transactions recognized into net income (7.8) 17.0 Change in fair value (1.5) 29.2 Cash flow transactions entered into for the period (9.4) 6.2 -------------------------------------------------------------------------- Net change associated with the current period hedging transactions (18.7) 52.4 -------------------------------------------------------------------------- Total fair value adjustments included in accumulated other comprehensive (loss)/income $(3.2) $15.5 -------------------------------------------------------------------------- Accumulated other comprehensive income items unrelated to NU's qualified cash flow hedging instruments totaled $0.3 million in gains and $0.6 million in losses at September 30, 2003 and December 31, 2002, respectively. These amounts primarily relate to unrealized gains and losses on investments in marketable debt and equity securities. 6. EARNINGS PER SHARE (NU) EPS is computed based upon the weighted average number of common shares outstanding during each period. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock. The following table sets forth the components of basic and fully diluted EPS: -------------------------------------------------------------------------- (Millions of Dollars, Nine Months Ended September 30, except share information) 2003 2002 -------------------------------------------------------------------------- Income before preferred dividends of subsidiaries $135.2 $100.3 Preferred dividends of subsidiaries 4.2 4.2 -------------------------------------------------------------------------- Income before cumulative effect of accounting change $131.0 $ 96.1 Cumulative effect of accounting change, net of tax benefit (4.7) - -------------------------------------------------------------------------- Net income $126.3 $ 96.1 -------------------------------------------------------------------------- Basic EPS common shares outstanding (average) 126,976,161 129,508,840 Dilutive effect of employee stock options 110,256 228,409 -------------------------------------------------------------------------- Fully diluted EPS common shares outstanding (average) 127,086,417 129,737,249 -------------------------------------------------------------------------- Basic and fully diluted EPS: Income before cumulative effect of accounting change $1.03 $0.74 Cumulative effect of accounting change, net of tax benefit (0.04) - -------------------------------------------------------------------------- Net income $0.99 $0.74 -------------------------------------------------------------------------- 7. SEGMENT INFORMATION (NU) NU is organized between the Utility Group and NU Enterprises based on each segments' regulatory environment or lack thereof. The Utility Group segment, including both electric and gas utilities, represents approximately 65 percent and 82 percent of NU's total revenues for the nine months ended September 30, 2003 and 2002, respectively, and primarily includes the operations of the electric utilities, CL&P, PSNH and WMECO, whose complete financial statements are included in NU's combined report on Form 10-Q. The Utility Group - gas segment includes the operations of Yankee Gas. Utility Group revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. The NU Enterprises segment includes Select Energy, NGC, SESI, NGS, and their respective subsidiaries. The ongoing generation operations of HWP and Woods Network are also included in the NU Enterprises segment. On January 1, 2000, Select Energy began serving one half of CL&P's standard offer load for a four-year period ending on December 31, 2003, at fixed prices. Total Select Energy revenues from CL&P for CL&P's standard offer load and for other transactions with CL&P, represented approximately $566 million or 23 percent for the nine months ended September 30, 2003 and approximately $473 million or 40 percent for the nine months ended September 30, 2002, of total NU Enterprises' revenues. Total CL&P purchases from NU Enterprises are eliminated in consolidation. Select Energy also provides basic generation service in the New Jersey market. Select Energy revenues related to these contracts represented approximately $324 million or 13 percent of total NU Enterprises' revenues for the nine months ended September 30, 2003. Short-term sales to ISO-NE represented approximately $264 million or 11 percent of total NU Enterprises' revenues for the nine months ended September 30, 2003. Additionally, WMECO's purchases from Select Energy represented approximately $110 million and $8 million of total NU Enterprises' revenues for the nine months ended September 30, 2003 and 2002, respectively. No other individual customer represented in excess of 10 percent of NU Enterprises' revenues for the nine months ended September 30, 2003 or 2002. Eliminations and other in the following table includes the results for Mode 1 Communications, Inc., an investor in a fiber-optic communications network, the results of the nonenergy-related subsidiaries of Yankee Energy System, Inc., (Yankee Energy Services Company, RMS, Yankee Energy Financial Services, and NorConn Properties, Inc.) the companies' parent and service companies, and the company's investment in Acumentrics Corporation. Interest expense included in eliminations and other primarily relates to the debt of NU parent. Inter-segment eliminations of revenues and expenses are also included in eliminations and other. Eliminations and other also includes NU's investment in RMS, which was consolidated with NU effective July 1, 2003, resulting in a negative $4.7 million net of tax cumulative effect of an accounting change. - ------------------------------------------------------------------------------- For the Three Months Ended September 30, 2003 - ------------------------------------------------------------------------------- Utility Group Eliminations (Millions of --------------- NU and Dollars) Electric Gas Enterprises Other Total - ------------------------------------------------------------------------------- Operating revenues $1,141.8 $30.6 $1,143.6 $(261.7) $2,054.3 Depreciation and amortization (134.7) (5.7) (4.6) (0.6) (145.6) Other operating expenses (887.8) (37.4) (1,115.1) 261.3 (1,779.0) - ------------------------------------------------------------------------------- Operating income/(loss) 119.3 (12.5) 23.9 (1.0) 129.7 Interest expense, net (42.8) (3.4) (13.5) (3.7) (63.4) Other income/ (loss), net 2.7 (0.4) 1.3 1.1 4.7 Income tax (expense)/ benefit (31.1) 6.7 (4.8) 3.5 (25.7) Preferred dividends (1.4) - - - (1.4) - ------------------------------------------------------------------------------- Income/(loss) before cumulative effect of accounting change 46.7 (9.6) 6.9 (0.1) 43.9 Cumulative effect of accounting change, net of tax benefit - - - (4.7) (4.7) - ------------------------------------------------------------------------------- Net income/ (loss) $ 46.7 $(9.6) $ 6.9 $ (4.8) $ 39.2 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- For the Nine Months Ended September 30, 2003 - ------------------------------------------------------------------------------- Utility Group Eliminations (Millions of --------------- NU and Dollars) Electric Gas Enterprises Other Total - ------------------------------------------------------------------------------- Operating revenues $3,130.3 $255.0 $2,499.1 $(684.1) $5,200.3 Depreciation and amortization (365.3) (17.2) (14.8) (1.8) (399.1) Other operating expenses (2,454.8) (220.4) (2,409.6) 682.5 (4,402.3) - ------------------------------------------------------------------------------- Operating income /(loss) 310.2 17.4 74.7 (3.4) 398.9 Interest expense, net (129.4) (9.9) (36.6) (10.6) (186.5) Other income/ (loss), net 2.3 (1.4) 4.2 0.9 6.0 Income tax (expense)/ benefit (71.3) (2.7) (18.3) 9.1 (83.2) Preferred dividends (4.2) - - - (4.2) - ------------------------------------------------------------------------------- Income/(loss) before cumulative effect of accounting change 107.6 3.4 24.0 (4.0) 131.0 Cumulative effect of accounting change, net of tax benefit - - - (4.7) (4.7) - ------------------------------------------------------------------------------- Net income/ (loss) $ 107.6 $ 3.4 $ 24.0 $ (8.7) $ 126.3 - ------------------------------------------------------------------------------- Total assets $7,719.5 $958.2 $2,031.9 $(111.2) $10,598.4 - ------------------------------------------------------------------------------- Total investments in plant $ 322.8 $ 37.7 $ 13.1 $ 12.4 $ 386.0 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- For the Three Months Ended September 30, 2002 - ------------------------------------------------------------------------------- Utility Group Eliminations (Millions of --------------- NU and Dollars) Electric Gas Enterprises Other Total - ------------------------------------------------------------------------------- Operating revenues $1,106.2 $ 37.8 $ 452.9 $(182.6) $1,414.3 Depreciation and amortization (134.1) (5.8) (5.0) (0.7) (145.6) Other operating expenses (840.9) (37.6) (449.7) 177.5 (1,150.7) - ------------------------------------------------------------------------------- Operating income/(loss) 131.2 (5.6) (1.8) (5.8) 118.0 Interest expense, net (46.6) (3.5) (11.1) (6.5) (67.7) Other income/ (loss), net 31.3 (0.5) 0.2 1.1 32.1 Income tax (expense)/ benefit (45.5) 3.8 3.7 5.6 (32.4) Preferred dividends (1.4) - - - (1.4) - ------------------------------------------------------------------------------- Net income/ (loss) $ 69.0 $(5.8) $ (9.0) $ (5.6) $ 48.6 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- For the Nine Months Ended September 30, 2002 - ------------------------------------------------------------------------------- Utility Group Eliminations (Millions of --------------- NU and Dollars) Electric Gas Enterprises Other Total - ------------------------------------------------------------------------------- Operating revenues $2,962.6 $192.8 $1,177.5 $(492.2) $3,840.7 Depreciation and amortization (321.1) (18.1) (17.0) (1.6) (357.8) Other operating expenses (2,298.9) (152.9) (1,187.6) 483.0 (3,156.4) - ------------------------------------------------------------------------------- Operating income/(loss) 342.6 21.8 (27.1) (10.8) 326.5 Interest expense, net (140.5) (10.9) (32.8) (19.4) (203.6) Other income/ (loss), net 33.4 (0.5) (0.5) (12.7) 19.7 Income tax (expense)/ benefit (79.0) (4.2) 21.7 19.2 (42.3) Preferred dividends (4.2) - - - (4.2) - ------------------------------------------------------------------------------- Net income/ (loss) $ 152.3 $ 6.2 $ (38.7) $ (23.7) $ 96.1 - ------------------------------------------------------------------------------- Total investments in plant $ 250.5 $ 41.8 $ 18.1 $ 16.9 $ 327.3 - ------------------------------------------------------------------------------- THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2003 2002 ---------------- ---------------- (Thousands of Dollars) ASSETS - ------ Current Assets: Cash $ 7,324 $ 159 Restricted cash - LMP costs 45,760 - Investments in securitizable assets 215,592 178,908 Receivables, net 62,896 88,001 Accounts receivable from affiliated companies 47,978 51,060 Unbilled revenues 7,422 5,801 Notes receivable from affiliated companies 26,175 1,900 Fuel, materials and supplies, at average cost 30,033 32,379 Prepayments and other 22,770 19,407 -------------- -------------- 465,950 377,615 -------------- -------------- Property, Plant and Equipment: Electric utility 3,281,684 3,139,128 Less: Accumulated depreciation 1,159,189 1,113,991 -------------- -------------- 2,122,495 2,025,137 Construction work in progress 217,233 153,556 -------------- -------------- 2,339,728 2,178,693 -------------- -------------- Deferred Debits and Other Assets: Regulatory assets 1,662,347 1,702,677 Prepaid pension 297,888 276,173 Other 114,855 96,925 -------------- -------------- 2,075,090 2,075,775 -------------- -------------- Total Assets $ 4,880,768 $ 4,632,083 ============== ==============
The accompanying notes are an integral part of these consolidated financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2003 2002 ---------------- ---------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION - ------------------------------ Current Liabilities: Accounts payable $ 238,833 $ 174,890 Accounts payable to affiliated companies 196,393 117,904 Accrued taxes 59,908 34,350 Accrued interest 9,956 10,077 Other 47,871 48,495 -------------- -------------- 552,961 385,716 -------------- -------------- Rate Reduction Bonds 1,153,822 1,245,728 -------------- -------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 713,133 756,461 Accumulated deferred investment tax credits 91,516 93,408 Deferred contractual obligations 212,604 234,537 Other 486,533 276,325 -------------- -------------- 1,503,786 1,360,731 -------------- -------------- Capitalization: Long-Term Debt 829,647 827,866 -------------- -------------- Preferred Stock - Nonredeemable 116,200 116,200 -------------- -------------- Common Stockholder's Equity: Common stock, $10 par value - authorized 24,500,000 shares; 6,035,205 shares outstanding in 2003 and 2002 60,352 60,352 Capital surplus, paid in 326,703 327,299 Retained earnings 337,547 308,554 Accumulated other comprehensive loss (250) (363) -------------- -------------- Common Stockholder's Equity 724,352 695,842 -------------- -------------- Total Capitalization 1,670,199 1,639,908 -------------- -------------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization $ 4,880,768 $ 4,632,083 ============== ==============
The accompanying notes are an integral part of these consolidated financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, ----------------------------- ----------------------------- 2003 2002 2003 2002 -------------- -------------- -------------- -------------- (Thousands of Dollars) Operating Revenues $ 797,896 $ 687,938 $ 2,119,080 $ 1,874,089 ------------ ------------ ------------ ------------ Operating Expenses: Operation - Fuel, purchased and net interchange power 506,369 406,194 1,279,785 1,109,391 Other 88,757 80,834 265,524 229,610 Maintenance 19,388 23,949 51,242 56,217 Depreciation 26,500 24,445 77,827 73,851 Amortization of regulatory assets, net 23,971 26,163 74,218 41,232 Amortization of rate reduction bonds 27,664 25,120 78,483 74,197 Taxes other than income taxes 32,096 28,287 111,464 107,006 ------------ ------------ ------------ ------------ Total operating expenses 724,745 614,992 1,938,543 1,691,504 ------------ ------------ ------------ ------------ Operating Income 73,151 72,946 180,537 182,585 Interest Expense: Interest on long-term debt 9,567 10,682 29,579 31,071 Interest on rate reduction bonds 17,398 18,789 53,304 57,273 Other interest 1,238 648 1,994 1,963 ------------ ------------ ------------ ------------ Interest expense, net 28,203 30,119 84,877 90,307 ------------ ------------ ------------ ------------ Other Income, Net 2,652 7,911 4,615 14,094 ------------ ------------ ------------ ------------ Income Before Income Tax Expense 47,600 50,738 100,275 106,372 Income Tax Expense 17,169 21,441 37,058 43,984 ------------ ------------ ------------ ------------ Net Income $ 30,431 $ 29,297 $ 63,217 $ 62,388 ============ ============ ============ ============
The accompanying notes are an integral part of these consolidated financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, ------------------------------ 2003 2002 ------------- ------------- (Thousands of Dollars) Operating Activities: Net income $ 63,217 $ 62,388 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation 77,827 73,851 Deferred income taxes and investment tax credits, net (52,396) (59,570) (Deferral)/amortization of recoverable energy costs (15,733) 23,463 Amortization of regulatory assets, net 74,218 41,232 Amortization of rate reduction bonds 78,483 74,197 Prepaid pension (21,715) (38,506) Regulatory recoveries 117,279 82,350 Other uses of cash (55,152) (34,656) Other sources of cash 8,957 16,804 Changes in current assets and liabilities: Restricted cash - LMP costs (45,760) - Receivables and unbilled revenues, net 26,566 (49,146) Fuel, materials and supplies 2,346 (925) Accounts payable 142,432 60,995 Accrued taxes 25,558 2,493 Investments in securitizable assets (36,684) 49,570 Other current assets and liabilities (excludes cash) (4,063) (1,383) ---------- ---------- Net cash flows provided by operating activities 385,380 303,157 ---------- ---------- Investing Activities: Investments in plant (224,757) (159,946) NU system Money Pool (lending)/borrowing (24,275) 51,000 Other investment activities, net (2,896) (683) ---------- ---------- Net cash flows used in investing activities (251,928) (109,629) ---------- ---------- Financing Activities: Repurchase of common shares - (49,996) Retirement of rate reduction bonds (91,606) (86,819) Cash dividends on preferred stock (4,169) (4,169) Cash dividends on common stock (30,055) (45,091) Other financing activities, net (457) (399) ---------- ---------- Net cash flows used in financing activities (126,287) (186,474) ---------- ---------- Net increase in cash 7,165 7,054 Cash - beginning of period 159 773 ---------- ---------- Cash - end of period $ 7,324 $ 7,827 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Financial Condition and Results of Operations CL&P is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management's discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the first and second quarter 2003 reports on Form 10-Q, and the NU 2002 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the third quarter of 2003 and the first nine months of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ------------------------------------ Third Nine Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $110 16% $245 13% Operating Expenses: Fuel, purchased and net interchange power 100 25 170 15 Other operation 8 10 36 16 Maintenance (5) (19) (5) (9) Depreciation 2 8 4 5 Amortization of regulatory assets, net (2) (8) 33 80 Amortization of rate reduction bonds 3 10 4 6 Taxes other than income taxes 4 13 5 4 ---- ---- ---- ---- Total operating expenses 110 18 247 15 ---- ---- ---- ---- Operating income - - (2) (1) ---- ---- ---- ---- Interest expense, net (2) (6) (5) (6) Other income, net (5) (66) (9) (67) ---- ---- ---- ---- Income before income tax expense (3) (6) (6) (6) Income tax expense (4) (20) (7) (16) ---- ---- ---- ---- Net income $ 1 4% $ 1 1% ==== ==== ==== ==== Comparison of the Third Quarter of 2003 to the Third Quarter of 2002 Operating Revenues Operating revenues increased $110 million or 16 percent in the third quarter of 2003, compared with the same period in 2002, primarily due to higher retail revenues resulting from the collection of incremental LMP costs beginning in May 2003 ($69 million) and from higher retail sales ($33 million) which includes a positive adjustment in estimated unbilled revenue of approximately $39 million. Retail sales increased 5.4 percent compared with the same period in 2002 after reflecting adjustments to unbilled sales. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased by $100 million or 25 percent in the third quarter of 2003, compared with the same period in 2002, primarily due to costs associated with SMD ($69 million) and higher standard offer purchased power expense as a result of higher retail sales ($15 million). Other Operation and Maintenance Other operation and maintenance (O&M) expenses increased $3 million in the third quarter of 2003, compared with the same period in 2002, primarily due to higher administrative costs ($7 million) resulting from higher health care costs and lower pension income and higher RMR related transmission expense ($3 million), partially offset by lower distribution costs ($5 million). Depreciation Depreciation expense increased $2 million primarily due to higher utility plant balances in 2003 resulting from plant additions. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net expense decreased $2 million primarily due to lower amortization of recoverable nuclear costs ($8 million), partially offset by higher amortization related to the recovery of stranded costs ($6 million). Taxes Other Than Income Taxes Taxes other than income taxes increased $4 million in the third quarter of 2003 due to the recognition in 2002 of a Connecticut sales and use tax audit settlement ($7 million), partially offset by a payment in 2002 to compensate the Town of Waterford for lost property tax revenue as a result of the sale of Millstone ($3 million). Interest Expense, Net Interest expense, net decreased $2 million primarily due to lower interest on rate reduction bonds. Other Income, Net Other income, net decreased $5 million primarily due to lower interest and dividend income ($2 million), lower equity in earnings from the nuclear entitlements ($2 million) and lower conservation and load management (C&LM) incentive income ($1 million). Income Tax Expense Income tax expense decreased $4 million primarily due to lower taxable income. Comparison of the First Nine Months of 2003 to the First Nine Months of 2002 Operating Revenues Operating revenues increased by $245 million or 13 percent in 2003, compared with the same period in 2002, primarily due to higher retail revenues ($179 million) and higher wholesale revenues ($64 million). Retail revenues were higher primarily due to the collection of incremental LMP costs beginning in May 2003 ($99 million) and higher retail sales ($79 million) which includes a positive adjustment in estimated unbilled revenue of approximately $39 million. Retail kilowatt-hour (kWh) sales increased by 4.8 percent in 2003 after reflecting adjustments to unbilled sales. Wholesale revenues were higher primarily due to higher market prices in 2003. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $170 million or 15 percent in 2003, primarily due to incremental LMP costs which were recovered from customers ($99 million) and higher standard offer purchases as a result of higher retail sales ($42 million). Other Operation and Maintenance Other O&M expenses increased by $31 million primarily due to higher administrative costs ($18 million) resulting from higher health care costs and lower pension income, higher RMR related transmission costs ($17 million), higher C&LM expenses ($7 million), partially offset by lower related nuclear expenses ($11 million) as a result of the final DPUC order regarding the CL&P Millstone use of proceeds docket in the first quarter of 2003. Depreciation Depreciation expense increased $4 million primarily due to higher utility plant balances in 2003 resulting from plant additions. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net expense increased $33 million primarily due to higher amortization related to the recovery of stranded costs ($63 million), partially offset by lower amortization of recoverable nuclear costs ($30 million). Taxes Other Than Income Taxes Taxes other than income taxes increased $5 million primarily due to the recognition in 2002 of a Connecticut sales and use tax audit settlement ($7 million), partially offset by a payment in 2002 to compensate the Town of Waterford for lost property tax revenue as a result of the sale of Millstone ($3 million). Interest Expense, Net Interest expense, net decreased $5 million primarily due to lower interest on rate reduction bonds. Other Income, Net Other income, net decreased $9 million primarily due to lower interest and dividend income ($3 million), lower equity in earnings from the nuclear entitlements ($3 million) and lower C&LM incentive income ($2 million). Income Tax Expense Income tax expense decreased $7 million primarily due to lower taxable income. LIQUIDITY CL&P's net cash flows provided by operating activities increased to $385.4 million for the nine months ended September 30, 2003 from $303.2 million for the same period in 2002. Cash flows provided by operating activities increased primarily due to the increase in the amortization of regulatory assets related to the recovery of stranded costs and increases in working capital items, offset by the placing of incremental LMP costs collected into an escrow account beginning in July 2003. On October 1, 2003, CL&P fixed the interest rate on $62 million of variable- rate tax-exempt borrowings for five years at 3.35 percent. CL&P's net cash flows used in investing activities increased to $251.9 million for the first nine months of 2003 from $109.6 million for the same period in 2002. The increase is primarily due to higher capital expenditures in 2003 and lower NU system Money Pool borrowings in 2003. CL&P's capital expenditures totaled $224.8 million in the first nine months of 2003 compared to $159.9 million in the first nine months of 2002. Financing activities decreased in 2003 as a result of the repurchase of common shares in 2002. In the first nine months of 2003, CL&P also repaid $91.6 million of rate reduction bonds. In the third quarter 2003, Fitch Ratings (Fitch) raised the outlook of CL&P's credit ratings to stable from negative. The change in outlook is a result of Fitch's belief that the risks associated with CL&P's standard offer service contract with NRG had declined. At September 30, 2003, CL&P had no borrowings outstanding on the Utility Group's $300 million revolving credit line. This credit line expires on November 11, 2003, and management expects to extend this credit line from November 2003 through November 2004. At September 30, 2003, CL&P had $40 million of accounts receivable and unbilled revenues sold under its arrangement with a financial institution to sell up to $100 million in accounts receivable and unbilled revenues. This arrangement expires in July 2004. CL&P is seeking approval from its preferred shareholders to permanently amend its charter to eliminate a requirement that unsecured debt represent no more than 10 percent of total capitalization. CL&P is offering its preferred holders a payment of 1 percent of the $116.2 million par value of their shares if the preferred holders vote in favor of the amendment and CL&P implements it. Preferred holders of record as of September 30, 2003, are eligible to vote at a special meeting, which will be held on November 25, 2003. Holders of at least two-thirds of CL&P's approximately 2.3 million shares of preferred stock must vote in favor of the change for it to pass. Management believes that CL&P will benefit from such a change due to increased financial flexibility. In the event that this change fails or if CL&P chooses not to implement it, CL&P is also asking preferred holders to endorse another 10-year waiver that would allow CL&P's unsecured debt to rise to 20 percent of total capitalization. At September 30, 2003, CL&P's unsecured debt represented approximately 3 percent of CL&P's total long-term debt. CL&P preferred holders approved a similar waiver in 1993 that is scheduled to expire in March 2004. Prior to July 1, 2003, CL&P recovered approximately $30 million of incremental LMP costs from its customers and has withheld payment of these incremental LMP costs from its standard offer service suppliers. This positively impacted CL&P's liquidity. In July 2003, CL&P began depositing new recoveries into an escrow account. Accordingly, further recovery of these costs did not impact CL&P's liquidity. When the LMP dispute is resolved, there will be a negative impact on CL&P's liquidity for the amounts recovered but not deposited into the escrow account, as these amounts are paid to standard offer service suppliers or returned to customers. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2003 2002 ---------------- -------------- (Thousands of Dollars) ASSETS - ------ Current Assets: Cash $ 5,782 $ 5,319 Receivables, net 68,966 68,204 Accounts receivable from affiliated companies 152 9,667 Unbilled revenues 35,450 32,004 Notes receivable from affiliated companies - 23,000 Fuel, materials and supplies, at average cost 52,087 49,182 Prepayments and other 17,257 10,032 ------------- ------------- 179,694 197,408 ------------- ------------- Property, Plant and Equipment: Electric utility 1,495,740 1,431,774 Other 6,180 6,195 ------------- ------------- 1,501,920 1,437,969 Less: Accumulated depreciation 718,860 715,800 ------------- ------------- 783,060 722,169 Construction work in progress 37,105 50,547 ------------- ------------- 820,165 772,716 ------------- ------------- Deferred Debits and Other Assets: Regulatory assets 972,042 1,026,043 Other 66,437 92,280 ------------- ------------- 1,038,479 1,118,323 ------------- ------------- Total Assets $ 2,038,338 $ 2,088,447 ============= =============
The accompanying notes are an integral part of these consolidated financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2003 2002 --------------- --------------- (Thousands of Dollars) LIABILITIES AND CAPITALIZATION - ------------------------------ Current Liabilities: Notes payable to affiliated companies $ 53,500 $ - Accounts payable 35,709 54,588 Accounts payable to affiliated companies 3,212 4,008 Accrued taxes 23,222 65,317 Accrued interest 14,437 11,333 Unremitted rate reduction bond collections 12,636 25,555 Other 17,513 12,674 -------------- -------------- 160,229 173,475 -------------- -------------- Rate Reduction Bonds 483,432 510,841 -------------- -------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 339,791 359,910 Accumulated deferred investment tax credits 2,242 2,680 Deferred contractual obligations 50,790 56,165 Accrued pension 43,080 37,933 Other 206,638 218,328 -------------- -------------- 642,541 675,016 -------------- -------------- Capitalization: Long-Term Debt 407,285 407,285 -------------- -------------- Common Stockholder's Equity: Common stock, $1 par value - authorized 100,000,000 shares; 301 shares outstanding in 2003 and 2002 - - Capital surplus, paid in 126,608 126,937 Retained earnings 218,292 194,998 Accumulated other comprehensive loss (49) (105) -------------- -------------- Common Stockholder's Equity 344,851 321,830 -------------- -------------- Total Capitalization 752,136 729,115 -------------- -------------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization $ 2,038,338 $ 2,088,447 ============== ==============
The accompanying notes are an integral part of these consolidated financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, -------------------------- ------------------------- 2003 2002 2003 2002 -------------------------- ------------------------- (Thousands of Dollars) Operating Revenues $ 241,829 $ 324,818 $ 718,988 $ 816,113 ----------- ----------- ----------- ----------- Operating Expenses: Operation - Fuel, purchased and net interchange power 110,121 190,152 362,581 460,575 Other 34,874 33,309 100,382 94,315 Maintenance 13,512 13,342 50,689 45,585 Depreciation 10,963 10,377 32,290 30,681 Amortization of regulatory assets, net 18,264 19,742 22,415 14,532 Amortization of rate reduction bonds 10,666 8,071 29,422 34,739 Taxes other than income taxes 8,655 8,896 25,384 27,003 ----------- ----------- ----------- ----------- Total operating expenses 207,055 283,889 623,163 707,430 ----------- ----------- ----------- ----------- Operating Income 34,774 40,929 95,825 108,683 Interest Expense: Interest on long-term debt 3,942 3,895 11,642 12,725 Interest on rate reduction bonds 7,237 7,584 21,981 23,022 Other interest 313 622 925 1,120 ----------- ----------- ----------- ----------- Interest expense, net 11,492 12,101 34,548 36,867 ----------- ----------- ----------- ----------- Other (Loss)/Income, Net (1,186) 231 (3,570) (887) ----------- ----------- ----------- ----------- Income Before Income Tax Expense 22,096 29,059 57,707 70,929 Income Tax Expense 9,483 9,577 23,213 24,487 ----------- ----------- ----------- ----------- Net Income $ 12,613 $ 19,482 $ 34,494 $ 46,442 =========== =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, ------------------------------ 2003 2002 ------------- ------------- (Thousands of Dollars) Operating activities: Net income $ 34,494 $ 46,442 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation 32,290 30,681 Deferred income taxes and investment tax credits, net (3,602) (17,446) Amortization of recoverable energy costs 17,541 12,494 Amortization of regulatory assets, net 22,415 14,532 Amortization of rate reduction bonds 29,422 34,739 Regulatory recoveries (1,593) (25,529) Other sources of cash 20,675 22,347 Other uses of cash (29,932) (21,724) Changes in current assets and liabilities: Receivables and unbilled revenues, net 5,307 7,496 Fuel, materials and supplies (2,905) 1,520 Accounts payable (19,673) (15,081) Accrued taxes (42,095) 24,963 Other current assets and liabilities (excludes cash) (12,126) 11,365 ----------- ----------- Net cash flows provided by operating activities 50,218 126,799 ----------- ----------- Investing Activities: Investments in plant (77,373) (75,817) NU system Money Pool borrowing/(lending) 76,500 (5,800) Buyout/buydown of IPP contracts (20,437) (5,152) Other investment activities, net 10,316 (8,179) ----------- ----------- Net cash flows used in investing activities (10,994) (94,948) ----------- ----------- Financing Activities: Issuance of rate reduction bonds - 50,000 Retirement of rate reduction bonds (27,409) (38,727) Net decrease in short-term debt - (5,500) Cash dividends on common stock (11,200) (24,500) Other financing activities, net (152) (13,885) ----------- ----------- Net cash flows used in financing activities (38,761) (32,612) ----------- ----------- Net increase/(decrease) in cash 463 (761) Cash - beginning of period 5,319 1,479 ----------- ----------- Cash - end of period $ 5,782 $ 718 =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES Management's Discussion and Analysis of Financial Condition and Results of Operations PSNH is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management's discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the first and second quarter 2003 reports on Form 10-Q, and the NU 2002 Form 10-K. RESULTS OF OPERATIONS The components of significant income statement variances for the third quarter of 2003 and for the first nine months of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ------------------------------------ Third Nine Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $(83) (26)% $(97) (12)% Operating Expenses: Fuel, purchased and net interchange power (80) (42) (98) (21) Other operation 2 5 6 6 Maintenance - - 5 11 Depreciation - - 2 5 Amortization of regulatory assets, net (1) (7) 8 54 Amortization of rate reduction bonds 2 32 (5) (15) Taxes other than income taxes - - (2) (6) ---- ---- ---- ---- Total operating expenses (77) (27) (84) (12) ---- ---- ---- ---- Operating income (6) (15) (13) (12) ---- ---- ---- ---- Interest expense, net - - (2) (6) Other income/(loss), net (1) (a) (2) (a) ---- ---- ---- ---- Income before income tax expense (7) (24) (13) (19) Income tax expense - - (1) (5) ---- ---- ---- ---- Net income $ (7) (35)% $(12) (26)% ==== ==== ==== ==== (a) Percent greater than 100. Comparison of the Third Quarter of 2003 to the Third Quarter of 2002 Operating Revenues Total operating revenues decreased $83 million or 26 percent in the third quarter of 2003 compared with the same period of 2002, due to lower wholesale revenues primarily due to the impact of the sale of Seabrook ($99 million), partially offset by higher retail revenue ($16 million) which includes a positive adjustment in estimated unbilled revenue of approximately $6 million. Retail kWh sales increased by 4.8 percent in 2003 after reflecting adjustments to unbilled sales. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased $80 million primarily due to lower purchased power expenses as a result of the absence of Seabrook power contract costs and lower wholesale sales. Other Operation and Maintenance Other O&M expenses increased $2 million primarily due to higher administrative costs primarily resulting from C&LM programs and low income program costs ($2 million) and higher distribution expenses ($1 million), partially offset by lower fossil production maintenance expense ($1 million). Amortization of Regulatory Assets, Net Amortization of regulatory assets, net decreased $1 million primarily due to decreased recovery of stranded costs resulting from the reconciliation of actual stranded cost revenues against actual stranded costs. Amortization of Rate Reduction Bonds Amortization of rate reduction bonds increased $2 million due to the scheduled repayment of principal. Comparison of the First Nine Months of 2003 to the First Nine Months of 2002 Operating Revenues Total operating revenues decreased $97 million or 12 percent in the first nine months of 2003 compared with the same period of 2002, due to lower wholesale revenues ($143 million) primarily due to the impact of the sale of Seabrook, partially offset by higher retail revenue ($47 million) which includes a positive adjustment in estimated unbilled revenue of approximately $6 million. Retail kWh sales increased by 5.5 percent in 2003 after reflecting adjustments to unbilled sales. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased $98 million, primarily due to lower purchased power expenses as a result of the absence of Seabrook power contract costs and lower wholesale sales. Other Operation and Maintenance Other O&M expense increased $11 million primarily due to higher administrative costs ($7 million) primarily resulting from C&LM programs and low income program costs and higher fossil production maintenance expenses ($4 million). Depreciation Depreciation increased $2 million primarily due to additions to distribution, generation and general plant assets. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net increased $8 million primarily due to increased recovery of stranded costs resulting from the reconciliation of actual stranded cost revenues against actual stranded costs. Amortization of Rate Reduction Bonds Amortization of rate reduction bonds decreased $5 million due to the scheduled repayment of principal. Taxes Other Than Income Taxes Taxes other than income taxes decreased $2 million primarily due to lower property taxes. Interest Expense, Net Interest expense, net decreased $2 million primarily due to lower interest costs associated with the refinancing of the pollution control revenue bonds. Other Income/(Loss), Net Other income/(loss), net decreased $2 million primarily due to increased service fees associated with rate reduction bonds and lower gains on the disposition of property in 2003. Income Tax Expense Income tax expense decreased $1 million primarily due to lower taxable income. LIQUIDITY PSNH's net cash flows provided by operating activities totaled $50.2 million for the nine months ended September 30, 2003, compared with $126.8 million for the same period of 2002. Cash flows provided by operating activities decreased due to changes in working capital items, primarily the payment of taxes on the gain on the sale of Seabrook. PSNH's net cash flows used in investing activities were $11 million for the nine months ended September 30, 2003 compared with $94.9 million for the same period in 2002. The decrease is primarily due to higher NU system Money Pool borrowings in 2003. PSNH's capital expenditures totaled $77.4 million in the first nine months of 2003 compared to $75.8 million in the first nine months of 2002. In the first nine months of 2003, PSNH also repaid $27.4 million of rate reduction bonds. At September 30, 2003, PSNH had no borrowings outstanding on the Utility Group's $300 million revolving credit line. This credit line expires on November 11, 2003, and management expects to extend this credit line from November 2003 through November 2004. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2003 2002 -------------- ------------- (Thousands of Dollars) ASSETS - ------ Current Assets: Cash $ 1 $ 123 Receivables, net 37,480 42,203 Accounts receivable from affiliated companies 2,458 6,354 Taxes receivable 1,218 - Unbilled revenues 9,811 8,944 Fuel, materials and supplies, at average cost 2,370 1,821 Prepayments and other 967 1,470 -------------- ------------- 54,305 60,915 -------------- ------------- Property, Plant and Equipment: Electric utility 602,915 590,153 Less: Accumulated depreciation 201,984 195,804 -------------- ------------- 400,931 394,349 Construction work in progress 16,125 11,860 -------------- ------------- 417,056 406,209 -------------- ------------- Deferred Debits and Other Assets: Regulatory assets 241,798 283,702 Prepaid pension 73,321 67,516 Other 21,011 18,304 -------------- ------------- 336,130 369,522 -------------- ------------- Total Assets $ 807,491 $ 836,646 ============== =============
The accompanying notes are an integral part of these consolidated financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (Unaudited)
September 30, December 31, 2003 2002 -------------- ------------ (Thousands of Dollars) LIABILITIES AND CAPITALIZATION - ------------------------------ Current Liabilities: Notes payable to banks $ - $ 7,000 Notes payable to affiliated companies 32,200 85,900 Accounts payable 19,106 17,730 Accounts payable to affiliated companies 12,088 6,218 Accrued taxes 412 4,334 Accrued interest 1,045 2,059 Other 10,097 8,005 ------------- ------------- 74,948 131,246 ------------- ------------- Rate Reduction Bonds 135,383 142,742 ------------- ------------- Deferred Credits and Other Liabilities: Accumulated deferred income taxes 208,719 222,065 Accumulated deferred investment tax credits 3,410 3,662 Deferred contractual obligations 57,804 63,767 Other 16,467 13,213 ------------- ------------- 286,400 302,707 ------------- ------------- Capitalization: Long-Term Debt 157,077 101,991 ------------- ------------- Common Stockholder's Equity: Common stock, $25 par value - authorized 1,072,471 shares; 434,653 shares outstanding in 2003 and 2002 10,866 10,866 Capital surplus, paid in 69,568 69,712 Retained earnings 73,317 77,476 Accumulated other comprehensive loss (68) (94) ------------- ------------- Common Stockholder's Equity 153,683 157,960 ------------- ------------- Total Capitalization 310,760 259,951 ------------- ------------- Commitments and Contingencies (Note 4) Total Liabilities and Capitalization $ 807,491 $ 836,646 ============= =============
The accompanying notes are an integral part of these consolidated financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, -------------------------- ------------------------- 2003 2002 2003 2002 ----------- ------------ ----------- ----------- (Thousands of Dollars) Operating Revenues $ 103,365 $ 95,684 $ 297,816 $ 278,880 ----------- ----------- ----------- ----------- Operating Expenses: Operation - Fuel, purchased and net interchange power 52,194 46,927 150,361 140,510 Other 16,070 12,516 43,611 37,083 Maintenance 3,785 3,798 10,378 10,029 Depreciation 3,544 3,415 10,530 11,038 Amortization of regulatory assets, net 10,647 12,092 32,819 26,277 Amortization of rate reduction bonds 2,399 2,189 7,327 7,080 Taxes other than income taxes 3,134 2,223 8,943 7,966 ----------- ----------- ----------- ----------- Total operating expenses 91,773 83,160 263,969 239,983 ----------- ----------- ----------- ----------- Operating Income 11,592 12,524 33,847 38,897 Interest Expense: Interest on long-term debt 767 880 2,303 2,172 Interest on rate reduction bonds 2,228 2,379 6,803 7,245 Other interest 127 542 848 1,377 ----------- ----------- ----------- ----------- Interest expense, net 3,122 3,801 9,954 10,794 ----------- ----------- ----------- ----------- Other Income/(Loss), Net 1,213 742 986 (2,342) ----------- ----------- ----------- ----------- Income Before Income Tax Expense/(Benefit) 9,683 9,465 24,879 25,761 Income Tax Expense/(Benefit) 4,488 4,735 11,030 (1,181) ----------- ----------- ----------- ----------- Net Income $ 5,195 $ 4,730 $ 13,849 $ 26,942 =========== =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, ------------------------------ 2003 2002 ------------ ----------- (Thousands of Dollars) Operating Activities: Net income $ 13,849 $ 26,942 Adjustments to reconcile to net cash flows provided by operating activities: Depreciation 10,530 11,038 Deferred income taxes and investment tax credits, net (11,272) (19,312) Amortization of recoverable energy costs 448 322 Amortization of regulatory assets, net 32,819 26,277 Amortization of rate reduction bonds 7,327 7,080 Prepaid pension (5,805) (10,264) Regulatory recoveries 2,879 8,849 Other sources of cash 1,800 16,580 Other uses of cash (11,183) (35,675) Changes in current assets and liabilities: Receivables and unbilled revenues, net 7,752 9,771 Fuel, materials and supplies (548) (232) Accounts payable 7,246 (23,839) Accrued taxes (3,922) 1,089 Other current assets and liabilities (excludes cash) 384 2,039 ---------- ---------- Net cash flows provided by operating activities 52,304 20,665 ---------- ---------- Investing Activities: Investments in plant (20,661) (14,739) NU system Money Pool (lending)/borrowing (53,700) 20,500 Other investment activities, net (676) 1,334 ---------- ---------- Net cash flows (used in)/provided by investing activities (75,037) 7,095 ---------- ---------- Financing Activities: Issuance of long-term debt 55,000 - Repurchase of common shares - (13,999) Retirement of rate reduction bonds (7,359) (7,337) Net (decrease)/increase in short-term debt (7,000) 5,000 Cash dividends on common stock (18,008) (12,005) Other financing activities, net (22) (17) ---------- ---------- Net cash flows provided by/(used in) financing activities 22,611 (28,358) ---------- ---------- Net decrease in cash (122) (598) Cash - beginning of period 123 599 ---------- ---------- Cash - end of period $ 1 $ 1 ========== ==========
The accompanying notes are an integral part of these consolidated financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY Management's Discussion and Analysis of Financial Condition and Results of Operations WMECO is a wholly owned subsidiary of NU. This discussion should be read in conjunction with NU's management's discussion and analysis of financial condition and results of operations, consolidated financial statements and footnotes in this Form 10-Q, the first and second quarter 2003 reports on Form 10-Q, the NU 2002 Form 10-K, and the current report on Form 8-K dated September 30, 2003. RESULTS OF OPERATIONS The components of significant income statement variances for the third quarter of 2003 and the first nine months of 2003 are provided in the table below. Income Statement Variances (Millions of Dollars) 2003 over/(under) 2002 ------------------------------------ Third Nine Quarter Percent Months Percent ------- ------- ------ ------- Operating Revenues $ 8 8% $ 19 7% Operating Expenses: Fuel, purchased and net interchange power 5 11 10 7 Other operation 4 28 7 18 Maintenance - - - - Depreciation - - (1) (5) Amortization of regulatory assets, net (1) (12) 7 25 Amortization of rate reduction bonds - - - - Taxes other than income taxes 1 41 1 12 ---- ---- ---- ---- Total operating expenses 9 10 24 10 ---- ---- ---- ---- Operating income (1) (7) (5) (13) ---- ---- ---- ---- Interest expense, net (1) (18) (1) (8) Other income/(loss), net - - 3 (a) ---- ---- ---- ---- Income before income tax expense/(benefit) - - (1) (3) Income tax expense/(benefit) - - 12 (a) ---- ---- ---- ---- Net income $ - -% $(13) (49)% ==== ==== ==== ==== (a) Percent greater than 100. Comparison of the Third Quarter of 2003 to the Third Quarter of 2002 Operating Revenues Operating revenues increased $8 million or 8 percent in 2003, compared with the same period in 2002, due to higher retail revenues ($7 million) and higher wholesale revenues ($1 million). Retail revenues were higher primarily due to an increase in the standard offer component of retail delivery rates and higher retail sales which includes a positive adjustment in estimated unbilled revenue of approximately $2 million. Retail kWh sales were 1.9 percent higher after reflecting adjustments to unbilled sales. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $5 million primarily due to higher standard offer purchases as a result of the higher standard offer contract costs and the retail sales increase. Other Operation Other operation expenses increased $4 million primarily due to higher general and administrative expenses resulting from higher health care costs and lower pension income. Comparison of the First Nine Months of 2003 to the First Nine Months of 2002 Operating Revenues Operating revenues increased by $19 million or 7 percent in 2003, compared with the same period in 2002, due to higher retail revenues ($13 million) and higher wholesale revenues ($6 million). Retail revenues were higher primarily due to an increase in the standard offer component of retail delivery rates and higher retail sales which includes a positive adjustment in estimated unbilled revenue of approximately $2 million. Retail kWh sales were 3.9 percent higher after reflecting adjustments to unbilled sales. Wholesale revenues were higher primarily due to higher wholesale sales. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased $10 million primarily due to higher standard offer purchases as a result of the retail sales increase and the higher standard offer contract costs. Other Operation Other operation expenses increased $6 million primarily due to higher general and administrative expenses resulting from higher health care costs and lower pension income. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net expense increased $7 million primarily due to the higher recovery of stranded costs. Other Income/(Loss), Net Other income/(loss), net increased $3 million primarily due to the 2002 adjustment to the gain from the 1999 sale of the fossil units as a result of a DTE decision in the annual stranded cost reconciliation filing for the period ended December 31, 1999. Income Tax Expense/(Benefit) Income tax expense/(benefit) increased $12 million primarily due to the recognition in 2002 of investment tax credits as a result of a 2002 DTE decision. LIQUIDITY WMECO's net cash flows provided by operating activities increased to $52.3 million for the first nine months of 2003 from $20.7 million for the same period of 2002. Net cash flows provided by operating activities increased primarily due to changes in working capital items, primarily accounts payable. On September 30, 2003, WMECO issued $55 million of ten-year 5 percent notes, the proceeds from which WMECO used to repay a similar level of borrowings from the NU system Money Pool. WMECO's net cash flows used in investing activities were $75 million for the nine months ended September 30, 2003, compared with net cash flows provided by investing activities of $7.1 million for the same period of 2002. The change is primarily due to lower NU system Money Pool borrowings in 2003. WMECO's capital expenditures totaled $20.7 million in the first nine months of 2003 compared to $14.7 million in the first nine months of 2002. In the first nine months of 2003, WMECO also repaid $7.4 million of rate reduction bonds. At September 30, 2003, WMECO had no borrowings outstanding on the Utility Group's $300 million revolving credit line. This credit line expires on November 11, 2003, and management expects to extend this credit line from November 2003 through November 2004. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The quantitative and qualitative disclosures about market risk are set forth in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," Note 2B, "Derivative Instruments, Market Risk and Risk Management - Market Risk Information," and Note 2C, "Derivative Instruments, Market Risk and Risk Management - Other Risk Management Activities," to the consolidated financial statements herein. ITEM 4. CONTROLS AND PROCEDURES NU, CL&P, PSNH and WMECO (collectively, the companies) evaluated the design and operation of their disclosure controls and procedures to determine whether they are effective in ensuring that the disclosure of required information is timely made in accordance with the Exchange Act and the rules and forms of the SEC. These evaluations were made under the supervision and with the participation of management, including the companies' principal executive officer and principal financial officer, as of the end of the period covered by this Quarterly Report on Form 10-Q. The principal executive officer and principal financial officer have concluded, based on their review, that the companies' disclosure controls and procedures are effective to ensure that information required to be disclosed by the companies in reports that it files under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. No significant changes were made to the companies' internal controls or other factors that could significantly affect these controls subsequent to the date of their evaluation. PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS 1. Consolidated Edison, Inc. v. NU - Merger Appeals and Related Litigation - United States District Court Litigation This litigation consists of the consolidated civil lawsuits filed in the United States District Court for the Southern District of New York (District Court) by Consolidated Edison, Inc. (Con Edison) and NU regarding the parties October 19, 1999 Agreement and Plan of Merger, as amended and restated as of January 11, 2000 (Merger Agreement). In its amended complaint, Con Edison alleges that NU failed to perform material obligations under the Merger Agreement, that there has been a "Material Adverse Change" with respect to NU and that certain conditions precedent to Con Edison's obligation to merge with NU have not been and cannot be satisfied. (Con Edison's amended complaint further asserts claims for fraud and negligent misrepresentation which were dismissed on summary judgment on March 15, 2003.) In its counterclaim, NU seeks damages in excess of $1 billion alleging that Con Edison is in material breach of the Merger Agreement based on its repudiation thereof and its refusal to proceed with the merger. As of June 19, 2003, the parties' motions in limine in the District Court case were fully briefed and are now pending before the District Court. Con Edison's July 1, 2003 motion to dismiss NU's "lost premium" counterclaim has also been fully briefed and is pending. On July 24, 2003, Robert Rimkoski filed a motion to intervene. On August 7, 2003, NU filed a brief in opposition to Mr. Rimkoski's motion to intervene. The motions in limine, motion to dismiss and motion to intervene are scheduled to be heard by the District Court on November 7, 2003. 2. NRG - Credit Rating Status On May 14, 2003, NRG and various affiliates filed for Chapter 11 protection in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court). The filing affects various relationships between NU companies and NRG. A. CL&P Standard Offer Contract NRG's May 14, 2003, bankruptcy filing included a request by NRG Power Marketing, Inc. (NRG-PM) to terminate service to CL&P under its standard offer supply agreement (SOS Agreement). The Bankruptcy Court authorized NRG- PM to reject the SOS Agreement, but the FERC directed NRG-PM to continue to perform under its SOS Agreement until the FERC fully considers the matter. Subsequently, the U.S. District Court for the Southern District of New York issued a ruling deferring to the FERC on this matter. On July 18, 2003, NRG- PM and the Creditors Committee filed an appeal with the U.S. Court of Appeals for the Second Circuit to enjoin the FERC order; this appeal is currently pending. On August 15, 2003, the FERC issued an order stating that NRG-PM had failed to demonstrate that premature termination of its SOS Agreement with CL&P would be in the public interest and, therefore, NRG-PM must continue to perform under the SOS Agreement. On September 15, 2003, NRG-PM and the Official Committee of Unsecured Creditors for NRG and its debtor subsidiaries (Committee) requested rehearing of the FERC's August 15, 2003, order and the FERC has not yet acted on that request. NRG-PM and the Committee also have filed appeals of the FERC's June 25, 2003 order and August 15, 2003 order denying rehearing with the D.C. District Court of Appeals. B. Station Service NRG has disputed its responsibility to pay for the provision of station service by CL&P to NRG's Connecticut generating plants. The FERC issued a decision on December 20, 2002, that NRG had agreed that station service from CL&P would be subject to CL&P's applicable retail rates, and that states have jurisdiction over the delivery of power to end users even where, as here, power is not delivered via distribution facilities. NRG refused CL&P's subsequent demand for payment, and on April 3, 2003, CL&P petitioned the DPUC for a declaratory order enforcing the FERC's December 20, 2002, decision. The DPUC proceeding was subsequently stayed due to the bankruptcy filing. On September 18, 2003, the Bankruptcy Court approved the parties' stipulation to submit the station service issue to arbitration for a determination of liability and damages which will fix CL&P's claim in bankruptcy. For additional information on certain matters involving NRG and its affiliates, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 4B, "NRG Energy, Inc. Exposures," within the notes to the consolidated financial statements in this combined report on Form 10-Q; "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Part II, Item 1. Legal Proceedings" in NU's report on Form 10-Q for the quarters ended March 31, 2003, and June 30, 2003, and "Part I, Item 1. Business - Rates and Electric Industry Restructuring - Connecticut" and "Part I, Item 3. Legal Proceedings" in NU's 2003 annual report on Form 10-K. 3. Connecticut Yankee Atomic Power Company Decommissioning Dispute On June 13, 2003, CYAPC gave notice of the termination of its contract with Bechtel for the decommissioning of the Connecticut Yankee nuclear power plant. CYAPC terminated the contract, after the failure of settlement discussions that occurred over an eight month period, due to Bechtel's history of incomplete and untimely performance and refusal to perform remaining decommissioning work. Under the agreement, Bechtel had 30 days to remedy its defaults before the termination became effective. On June 23, 2003, Bechtel filed a complaint against CYAPC in Connecticut Superior Court in Middletown, Connecticut. Bechtel's complaint asserts a number of claims and seeks a variety of remedies, including monetary and punitive damages and rescission of the contract. Bechtel has since amended its complaint to add claims for wrongful termination. On August 22, 2003, CYAPC filed its answer and counterclaims, including counts for breach of contract, negligent misrepresentation and breach of duty of good faith and fair dealing. Bechtel has departed the site and the decommissioning responsibility has been transitioned to CYAPC, which has recommenced the decommissioning process. NU's electric operating subsidiaries collectively own 49.0 percent of CYAPC, as follows: CL&P - 34.5 percent, PSNH - 5.0 percent and WMECO - 9.5 percent. For further information relating to this proceeding, see Note 4D, "Deferred Contractual Obligation - Connecticut Yankee Atomic Power Company (CYAPC) Decommissioning Dispute," within the notes to the consolidated financial statements in this combined report of Form 10-Q. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Listing of Exhibits (NU) Exhibit No. Description ----------- ----------- 15 Deloitte & Touche LLP Letter Regarding Unaudited Financial Information 31 Certification of Michael G. Morris, Chairman, President and Chief Executive Officer of Northeast Utilities, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 31.1 Certification of John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 32 Certification of Michael G. Morris, Chairman, President and Chief Executive Officer of Northeast Utilities and John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 (a) Listing of Exhibits (CL&P) 4.2.7.5 Compensation and Multiannual Mode Agreement among the Connecticut Development Authority, The Connecticut Light and Power Company and BNY Capital Markets, Inc. dated September 23, 2003 4.2.8.2 Amendment No. 3 to the Amended and Restated Receivables Purchase and Sales Agreement dated as of July 9, 2003 (CL&P and CRC) 31 Certification of Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 31.1 Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 32 Certification of Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power Company and John H. Forsgren, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 (a) Listing of Exhibits (PSNH) 31 Certification of Cheryl W. Grise, Chief Executive Officer of Public Service Company of New Hampshire, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 31.1 Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 32 Certification of Cheryl W. Grise, Chief Executive Officer of Public Service Company of New Hampshire and John H. Forsgren, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 (a) Listing of Exhibits (WMECO) 4.4.3 Underwriting Agreement between WMECO and the Underwriters named therein, dated September 25, 2003 (Exhibit 99.1, WMECO Form 8-K filed October 8, 2003, File No. 0-7624) 4.4.4 Indenture Agreement between WMECO and the Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.2, WMECO Form 8-K filed October 8, 2003, File No. 0- 7624) 4.4.5 First Supplemental Indenture Agreement between WMECO and the Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.3, WMECO Form 8-K filed October 8, 2003, File No. 0-7624) 31 Certification of Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 31.1 Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 32 Certification of Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric Company and John H. Forsgren, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated November 7, 2003 (b) Reports on Form 8-K: WMECO filed a current report on Form 8-K dated September 30, 2003, disclosing: o The completion of the issuance and sale to the public of $55 million of 5 percent Senior Notes, Series A, due 2013. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. NORTHEAST UTILITIES ------------------- Registrant Date: November 7, 2003 By /s/ John H. Forsgren ---------------- ------------------------------------- John H. Forsgren Vice Chairman, Executive Vice President and Chief Financial Officer (for the Registrant and as Principal Financial Officer) SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. THE CONNECTICUT LIGHT AND POWER COMPANY --------------------------------------- Registrant Date: November 7, 2003 By /s/ John H.Forsgren ---------------- ------------------------------------- John H. Forsgren Executive Vice President and Chief Financial Officer (for the Registrant and as Principal Financial Officer) SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE --------------------------------------- Registrant Date: November 7, 2003 By /s/ John H. Forsgren ---------------- ------------------------------------- John H. Forsgren Executive Vice President and Chief Financial Officer (for the Registrant and as Principal Financial Officer) SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. WESTERN MASSACHUSETTS ELECTRIC COMPANY -------------------------------------- Registrant Date: November 7, 2003 By /s/ John H. Forsgren ---------------- ------------------------------------- John H. Forsgren Executive Vice President and Chief Financial Officer (for the Registrant and as Principal Financial Officer) EX-15 3 exhibit15.txt EXHIBIT 15 Exhibit 15 November 7, 2003 Northeast Utilities 107 Selden Street Berlin, CT 06037 We have made a review, in accordance with standards established by the American Institute of Certified Public Accountants, of the unaudited interim financial information of Northeast Utilities and subsidiaries for the periods ended September 30, 2003 and 2002, as indicated in our report dated November 7, 2003; because we did not perform an audit, we expressed no opinion on that information. We are aware that our report referred to above, which is included in your Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, is incorporated by reference in Registration Statement Nos. 33-34622, 333-55142, 33-40156, 333-105273, and 333-108712 on Forms S-3 and Nos. 33-44814, 33- 63023, 333-52413, 333-52415, 333-106008, and 333-63144 on Forms S-8 of Northeast Utilities. We also are aware that the aforementioned report, pursuant to Rule 436(c) under the Securities Act of 1933, is not considered a part of the Registration Statement prepared or certified by an accountant or a report prepared or certified by an accountant within the meaning of Sections 7 and 11 of that Act. /s/ Deloitte & Touche LLP Deloitte & Touche LLP Hartford, Connecticut EX-31 4 morris31nu.txt EXHIBIT 31 NU MORRIS Exhibit 31 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Michael G. Morris, Chairman, President and Chief Executive Officer of Northeast Utilities (the registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 7, 2003 /s/ Michael G. Morris (Signature) Michael G. Morris Chairman, President and Chief Executive Officer EX-31.1 5 forsgren31nu.txt EXHIBIT 31.1 NU FORSGREN Exhibit 31.1 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities (the registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 7, 2003 /s/ John H. Forsgren (Signature) John H. Forsgren Vice Chairman, Executive Vice President and Chief Financial Officer EX-32 6 exhibit32nu.txt EXHIBIT 32 NU Exhibit 32 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Northeast Utilities (the registrant) on Form 10-Q for the period ending September 30, 2003 as filed with the Securities and Exchange Commission (the Report), we, Michael G. Morris, Chairman, President and Chief Executive Officer of the registrant and John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that: 1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant. /s/ Michael G. Morris (Signature) Michael G. Morris Chairman, President and Chief Executive Officer /s/ John H. Forsgren (Signature) John H. Forsgren Vice Chairman, Executive Vice President and Chief Financial Officer November 7, 2003 A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request. EX-4.2.7.5 7 exh4275clpcompagmt.txt COMPENSATION AND MULTIANNUAL MODE AGREEMENT Exhibit 4.2.7.5 EXECUTION COPY COMPENSATION AND MULTIANNUAL MODE AGREEMENT September 23, 2003 Morgan Stanley & Co., Incorporated as Senior Remarketing Agent BNY Capital Markets, Inc. as co-Remarketing Agent c/o Morgan Stanley & Co., Incorporated 1221 Avenue of the Americas, 30th Floor New York, NY 10020 Reference is made to (i) the Remarketing Agent's Agreement, dated as of May 1, 1996, by and among the Connecticut Development Authority ("CDA"), The Connecticut Light and Power Company (the "Company") and BNY Capital Markets, Inc. (`BNYCMI') as successor remarketing agent (the "Remarketing Agreement"), (ii) the Direction to Appoint Senior Remarketing Agent and Co-Remarketing Agent dated September 17, 2003 (the "Direction to Appoint") by and among the Company and CDA, and agreed and accepted by Morgan Stanley & Co., Incorporated ("Morgan Stanley") and BNYCMI under which Morgan Stanley was appointed Senior Remarketing Agent and BNYCMI was appointed Co-Remarketing Agent (together with the Senior Remarketing Agent, the "Remarketing Agents") and (iii) the Amended and Restated Indenture of Trust dated as of May 1, 1996, and amended and restated as of January 1, 1997, between the CDA and U.S. Bank National Association, as successor Trustee (the "Indenture") pursuant to which the CDA issued $62,000,000 Connecticut Development Authority Pollution Control Revenue Bonds (The Connecticut Light and Power Company Project -1996A Series) (the "Bonds"). Terms initially capitalized but not defined herein shall have the meaning ascribed to them in the Indenture. Intending to be legally bound, the parties hereto agree as follows: 1. BNYCMI is currently acting as the sole Remarketing Agent under the Remarketing Agreement. In accordance with Section 6 of the Remarketing Agreement and the Direction to Appoint, the parties agree that Morgan Stanley and BNYCMI shall act as Senior Remarketing Agent and co-Remarketing Agent, respectively, under the Remarketing Agreement in connection with the Remarketing (as defined below). Such appointments shall be effective as of the date of this Agreement; provided that, except for the obligations undertaken by the Remarketing Agents as described in the next paragraph, BNYCMI shall continue to act as sole remarketing agent of the Bonds in the Weekly Mode under the Remarketing Agreement until the Bonds are converted to the Multiannual Mode. In connection with the Remarketing of the Bonds, BNYCMI shall act as co-Remarketing Agent and shall have only those further responsibilities under the Remarketing Agreement as shall be agreed between it and the Senior Remarketing Agent. 2. Compensation. Subject to the terms and conditions of this Agreement and the Remarketing Agreement, the Remarketing Agents each severally agree to use their best efforts to remarket the Bonds in the Multiannual Mode for a Rate Period of five years, commencing on October 1, 2003, in accordance with the Indenture, the Supplement and the Reoffering Circular described below (the "Remarketing"). Pursuant to Article 2 of the Remarketing Agreement, and in consideration of the services to be performed by the Remarketing Agents hereunder and under the Remarketing Agreement, the Company agrees to pay to the Senior Remarketing Agent, for the benefit of itself and the Co- Remarketing Agent, a fee of $310,000 (the "Fee") in respect of the Remarketing. The Remarketing Agents agree to apportion the Fee between themselves on such basis as they shall mutually agree, and jointly and severally agree to indemnify the Company for any claims arising out of such apportionment. In addition, the Company will pay, or cause to be paid, all expenses incident to the Remarketing, including, without limitation, all costs of printing and mailing the Preliminary and Final Supplements dated September 17, 2003 and September 23, 2003, respectively, to Reoffering Circular dated January 20, 1997 (the "Reoffering Circular"), including the Reoffering Circular itself and the other appendices thereto and the documents incorporated by reference therein (collectively, the "Supplement") and any amendments or supplements thereto, all other documents prepared in connection with the Remarketing, and the reasonable fees and expenses of counsel for the Remarketing Agents. The Fee shall be payable on the Remarketing Date (as defined below) in immediately available funds by wire transfer to the account designated in writing by the Senior Remarketing Agent. 3. Representations and Warranties. The Company represents and warrants to and agrees with the Remarketing Agents that: (a) The Company and its subsidiaries have been duly formed, are validly existing as corporations in good standing under the laws of the jurisdictions of their organization, have the power and authority to own their property and to conduct their business as described in the Supplement and are duly qualified to transact business and are in good standing in each jurisdiction in which the conduct of their business or their ownership or leasing of property requires such qualification, except to the extent that the failure to be so qualified or be in good standing would not have a material adverse effect on the Company or its subsidiaries, taken as a whole. The Company and its subsidiaries possess such material certificates, authorizations, franchises or permits issued by the appropriate state or federal regulatory authorities or bodies as are necessary to conduct their businesses as currently conducted. (b) This Agreement has been duly authorized, executed and delivered by the Company. The Remarketing Agreement is a valid and binding agreement of the Company and the Remarketing Agents are entitled to the benefits thereunder. (c) The execution and delivery by the Company of, and the performance by the Company of its obligations under, this Agreement will not contravene any provision of applicable law or the Certificate of Incorporation or By-Laws of the Company or any agreement or other instrument binding upon the Company that is material to the Company, or any judgment, order or decree of any governmental body, agency or court having jurisdiction over the Company, and no consent, approval, authorization or order of, or qualification with, any governmental body or agency is required for the performance by the Company of its obligations under this Agreement. (d) The Supplement does not, and any supplement or amendment thereto will not, contain any untrue statement of a material fact or omit to state any material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading, except that the representations and warranties contained in this Section 1(d) shall not apply to (i) Appendix B to the Supplement, (ii) Appendices C, D, E, or F to the Reoffering Circular, (iii) the information in the Reoffering Circular under the captions "The Authority," "The Bonds - Book-Entry Only System," "Ambac Indemnity Corporation," "Tax Matters," "Litigation - The Authority," "Non-Impairment Pledge of the State," "Legality for Investment," or "Legal Matters," or (iv) statements in or omissions from the Supplement (or any supplement or amendment thereto) based upon information relating to the Remarketing Agents furnished to the Company in writing by the Remarketing Agents expressly for use therein. 4. Conditions to the Remarketing Agents' Obligations. The obligations of the Remarketing Agents shall be subject to (i) the condition that all representations and warranties and other statements of the Company herein are, at and as of the date hereof and as of October 1, 2003 (the "Remarketing Date"), true and correct, and the Remarketing Agents shall have received on the Remarketing Date a certificate, dated the Remarketing Date and signed by an executive officer of the Company, to that effect, (ii) the condition that the Company shall have performed all of its obligations hereunder to be performed at or prior to the Remarketing Date, and (ii) the following additional conditions: (a) At the Remarketing Date, the Remarketing Agents shall be furnished with the following opinions, dated the Remarketing Date: (i) an opinion of Day, Berry & Howard LLP, special counsel to the Company, to the effect that the statements made in the Supplement under the captions "Introductory Statement" and "Conversion to Multiannual Mode" and in the Reoffering Circular under the captions "Introductory Statement," "The Bonds" (other than under the subcaption "Book-Entry Only System," as to which such special counsel need express no opinion), "The Loan Agreement," "The Tax Regulatory Agreement," "The Indenture," "The Mortgage Bonds and the Mortgage," "The Insurance Policy," and "Continuing Disclosure" to the extent they constitute summaries of legal matters or documents referred to therein are accurate in all material respects, and as to such other matters as the Remarketing Agents may reasonably request. (ii) an opinion of Jeffrey C. Miller, Esq., Assistant General Counsel of Northeast Utilities Service Company, to the effect that no facts have come to his attention that have caused him to believe that Appendix A to the Supplement, including the documents incorporated by reference therein, as of the Remarketing Date, contained or contains an untrue statement of a material fact or omitted or omits to state a material fact necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading (except that in each case he is not required to express any view as to the financial statements, schedules and other financial data and financial projections included therein or excluded therefrom). (iii) the opinion of Winston & Strawn LLP, Bond Counsel, required under the Indenture to be delivered upon the occasion of the conversion of the Bonds to the Multiannual Mode, which opinion shall permit the Remarketing Agents to rely thereon. (b) The Remarketing Agents shall have received an agreed upon procedures letter from Deloitte & Touche LLP, dated the Remarketing Date (A) confirming that they are independent public accountants with respect to the Company within the meaning of the Securities Act of 1933, as amended, and the applicable rules and regulations adopted by the Securities and Exchange Commission (the "Commission") thereunder, (B) stating that in their opinion the financial statements examined by them and incorporated by reference in the Supplement complied as to form in all material respects with the applicable accounting requirements of the Commission, including the applicable rules and regulations adopted by the Commission, and (C) covering, as of a date not more than three business days prior to the date of such letter, such other matters as the Remarketing Agents reasonably request. (c) At the Remarketing Date the Bonds shall have the benefit of the Ambac Assurance Corporation policy described in the Supplement and the Reoffering Circular, and the Remarketing Agents shall have received evidence satisfactory to them that the Bonds have been rated at least "AAA" by S&P and "Aaa" by Moody's. 5. Effectiveness and Termination of Agreement. (a) This Agreement shall become effective upon the execution and delivery of this Agreement by the parties hereto. (b) This Agreement shall terminate as to a Remarketing Agent upon and resignation of such Remarketing Agent under paragraph 6 of the Remarketing Agreement, provided that the reference in clause (vii) thereof shall be deemed to refer to the Supplement. 6. Counterparts. This Agreement may be signed in two or more counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument. 7. Governing Law. This Agreement shall be governed by and construed in accordance with the internal laws of the State of New York. Please confirm your agreement by having an authorized officer sign a copy of this Agreement in the space set forth below. Very truly yours, THE CONNECTICUT LIGHT AND POWER COMPANY By: /s/ Randy A. Shoop Randy A. Shoop Title: Treasurer Accepted and agreed: MORGAN STANLEY & CO., INCORPORATED By: /s/ F. J. Sweeney Name: F. J. Sweeney Title: Managing Director BNY CAPITAL MARKETS INC. By: /s/ Daniel C. deMenocal, Jr. Name: Daniel C. deMenocal, Jr. Title: Managing Director EX-4.2.8.2 8 exh4282receivables.txt RESTATED RECEIVABLES PURCHASE AND SALE AGREEMENT Exhibit 4.2.8.2 AMENDMENT NO. 3 TO AMENDED AND RESTATED RECEIVABLES PURCHASE AND SALE AGREEMENT AMENDMENT AGREEMENT, dated as of July 9, 2003, among CL&P RECEIVABLES CORPORATION, a Connecticut corporation (the "Seller"), THE CONNECTICUT LIGHT AND POWER COMPANY, a Connecticut corporation, ("CL&P") as Collection Agent and Originator, CORPORATE ASSET FUNDING COMPANY, INC., a Delaware corporation ("CAFCO"), CITIBANK, N.A. ("Citibank" ) and CITICORP NORTH AMERICA, INC., a Delaware corporation ("CNAI"), as agent ("Agent"). Preliminary Statements. (1) The Seller, CL&P, CAFCO, Citibank and CNAI, as Agent, are parties to an Amended and Restated Receivables Purchase and Sale Agreement dated as of September 30, 1997, as amended and restated as of March 30, 2001 and as further amended as of July 11, 2001, and as of July 10, 2002, (the "Agreement"; capitalized terms not otherwise defined herein shall have the meanings attributed to them in the Agreement), pursuant to which the Seller is prepared to sell undivided fractional ownership interests of its Receivables to the Conduit and the Banks; and (2) The Seller, CL&P, CAFCO, Citibank and CNAI, as Agent, desire to amend the Agreement. NOW, THEREFORE, the parties hereto hereby agree as follows: SECTION 1. Amendments to Agreement. Subject to the condition precedent set forth in Section 2 hereof, the Agreement is amended effective as of the date set forth above as follows: 1.1 Section 1.01 of the Agreement is amended by deleting the date "July 9, 2003" in line one (1) of the definition of "Commitment Termination Date" and replacing it with the date "July 7, 2004." 1.2 Section 2.08(a) of the Agreement is amended in its entirety to read as follows: "(a) If CNAI, any Purchaser, any Bank, any entity which enters into a commitment to purchase Receivable Interests or interests therein, or any of their respective Affiliates (each an "Affected Person") determines that (i) compliance with any law or regulation or any guideline or request from any central bank or other governmental authority (whether or not having the force of law) affects or would affect the amount of the capital required or expected to be maintained by such Affected Person and such Affected Person determines that the amount of such capital is increased by or based upon the existence of any commitment to make purchases of or otherwise to maintain the investment in Pool Receivables or interests therein related to this Agreement or to the funding thereof and other commitments of the same type, or (ii) as a result of the existence of, or occurrence of any change in, accounting standards (including the issuance of any pronouncement, interpretation or release), all or any portion of the assets and liabilities of the Conduit, including the assets and liabilities which are the subject of this Agreement and the other Transaction Documents, are consolidated (for financial and/or regulatory accounting purposes) with those of such Affected Person (other than the Conduit), then, upon demand by such Affected Person (with a copy to the Agent), the Seller shall immediately pay to the Agent for the account of such Affected Person (as a third- party beneficiary), from time to time as specified by such Affected Person, additional amounts sufficient to compensate such Affected Person in the light of such circumstances, in the case of clause (i), to the extent that such Affected Person reasonably determines such increase in capital to be allocable to the existence of any of such commitments, and, in the case of clause (ii), to the extent of any increased cost, increased capital charge or reduced return resulting from the consolidation of the assets and liabilities which are the subject of this Agreement and the other Transaction Documents, as reasonably determined by such Affected Person. A certificate as to such amounts submitted to the Seller and the Agent by such Affected Person shall be conclusive and binding for all purposes, absent manifest error." 1.3 Section 10.06 of the Agreement is amended by adding the following new subsection (c) thereto: "(c) Notwithstanding any other provisions herein, each party hereto (and each employee, representative or other agent of each party hereto)may disclose to any and all Persons, without limitation of any kind, the U.S. tax treatment and U.S. tax structure of the transaction contemplated by this Agreement and the other Transaction Documents and all materials of any kind (including opinions or other tax analyses) that are provided to such party relating to such U.S. tax treatment and U.S. tax structure, other than any information for which nondisclosure is reasonably necessary in order to comply with applicable securities laws." SECTION 2. Condition Precedent. The effectiveness of this Amendment Agreement and the obligations of the Conduit and the Banks to make any Purchase on or after July 9, 2003 is conditioned upon the receipt by the Agent of evidence satisfactory to it that (a) the DPUC and the Securities and Exchange Commission have granted such approvals as may be necessary in connection with the implementation of this Amendment Agreement, or (b) such approvals required in connection herewith as have heretofore been granted remain in full force and effect thus requiring no further approvals. SECTION 3. Confirmation of Agreement. Except as herein expressly amended, the Agreement is ratified and confirmed in all respects and shall remain in full force and effect in accordance with its terms. Each reference in the Agreement to "this Agreement," "hereof" or words of like import shall mean the Agreement as amended by this Amendment Agreement and as hereinafter amended or restated. SECTION 4. GOVERNING LAW. THIS AMENDMENT AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK. SECTION 5. Execution in Counterparts. This Amendment Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which when taken together shall constitute one and the same Amendment Agreement. Delivery of an executed counterpart of a signature page to this Amendment Agreement by facsimile shall be effective as delivery of a manually executed counterpart of this Amendment Agreement. SECTION 6. Seller's Representations and Warranties. The Seller represents and warrants that this Amendment Agreement has been duly authorized, executed and delivered by the Seller pursuant to its corporate powers and constitutes the legal, valid and binding obligation of the Seller. The Seller also makes each of the representations and warranties contained in Section 4.01 of the Agreement (after giving effect to this Amendment Agreement) as of the date hereof. [Remainder of page intentionally left blank] IN WITNESS WHEREOF, the parties have caused this Amendment Agreement No. 3 to be executed by their respective officers thereunto duly authorized, as of the date first above written. CL&P RECEIVABLES CORPORATION By: /s/ Randy A. Shoop Name: Randy A. Shoop Title: Treasurer THE CONNECTICUT LIGHT AND POWER COMPANY By: /s/ Randy A. Shoop Name: Randy A. Shoop Title: Treasurer - CL&P CORPORATE ASSET FUNDING COMPANY, INC. By: Citicorp North America, Inc., as Attorney-in-Fact By: /s/ Richard Simons Name: Richard Simons Title: Vice President CITIBANK, N.A. By: /s/ Richard Simons Name: Richard Simons Title: Vice President CITICORP NORTH AMERICA, INC., as Agent By: /s/ Richard Simons Name: Richard Simons Title: Vice President EX-31 9 clp31grise.txt CLP GRISE Exhibit 31 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power Company (the registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 7, 2003 /s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer EX-31.1 10 clp311forsgren.txt CLP FORSGREN Exhibit 31.1 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John H. Forsgren, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company (the registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 7, 2003 /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer EX-32 11 clp32.txt CLP EXHIBIT 32 Exhibit 32 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of The Connecticut Light and Power Company (the registrant) on Form 10-Q for the period ending September 30, 2003 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grise, Chief Executive Officer of the registrant and John H. Forsgren, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that: 1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant. /s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer November 7, 2003 A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request. EX-31 12 psnh31grise.txt PSNH GRISE Exhibit 31 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Cheryl W. Grise, Chief Executive Officer of Public Service Company of New Hampshire (the registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 7, 2003 /s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer EX-31.1 13 psnh311forsgren.txt PSNH FORSGREN Exhibit 31.1 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John H. Forsgren, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire (the registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 7, 2003 /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer EX-32 14 psnh32.txt PSNH EXHIBIT 32 Exhibit 32 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Public Service Company of New Hampshire (the registrant) on Form 10-Q for the period ending September 30, 2003 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grise, Chief Executive Officer of the registrant, and John H. Forsgren, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that: 1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant. /s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer November 7, 2003 A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request. EX-31 15 wmeco31grise.txt WMECO GRISE Exhibit 31 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric Company (the registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 7, 2003 /s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer EX-31.1 16 wmeco311.txt WMECO FORSGREN Exhibit 31.1 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, John H. Forsgren, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company (the registrant), certify that: 1. I have reviewed this quarterly report on Form 10-Q of the registrant; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 7, 2003 /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer EX-32 17 wmeco32.txt WMECO EXHIBIT 32 Exhibit 32 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Western Massachusetts Electric Company (the registrant) on Form 10-Q for the period ending September 30, 2003 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grise, Chief Executive Officer of the registrant, and John H. Forsgren, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that: 1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant. /s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer /s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer November 7, 2003 A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----