-----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, FYSKlp6r3Ucr12N4YGD6eSL3NoROm1T5GUzeqSNKbj2V1u5EE3uP5JJXyPLvnovA c53DY/09FAauVvWJIttyPg== 0000072741-00-000041.txt : 20000302 0000072741-00-000041.hdr.sgml : 20000302 ACCESSION NUMBER: 0000072741-00-000041 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20000229 ITEM INFORMATION: FILED AS OF DATE: 20000229 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: 8-K SEC ACT: SEC FILE NUMBER: 001-05324 FILM NUMBER: 556712 BUSINESS ADDRESS: STREET 1: 174 BRUSH HILL AVE CITY: WEST SPRINGFIELD STATE: MA ZIP: 01090-0010 BUSINESS PHONE: 4137855871 MAIL ADDRESS: STREET 1: 107 SELDON ST CITY: BERLIN STATE: CT ZIP: 06037-1616 8-K 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549-1004 --------------------------- FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report February 29, 2000 NORTHEAST UTILITIES ------------------- (Exact name of registrant as specified in its charter) MASSACHUSETTS 1-5324 04-2147929 ------------ ------ ---------- State or other Commission I.R.S. Employer jurisdiction of File No.) Identification No.) incorporation or organization) 174 BRUSH HILL AVENUE WEST SPRINGFIELD, MASSACHUSETTS 01090-0010 ------------------------------------------- (Address of principal executive offices) Registrant's telephone number, including area code (413) 785-5871 INFORMATION TO BE INCLUDED IN THE REPORT ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS (c) Exhibits 23 Consent of Arthur Andersen LLP 27 Financial Data Schedule (To the extent provided in Rule 402 of Regulation S-T, this exhibit shall not be deemed "filed", or otherwise subject to liabilities, or be deemed part of a registration statement.) 99.1 Consolidated balance sheet and statement of capitalization at December 31, 1999 and 1998, and related consolidated statements of income, of retained earnings, and of cash flows for each of the three years in the period ended December 31, 1999, and the notes thereto, of Northeast Utilities and its subsidiaries ("1999 Financial Statements"). 99.2 Report of Arthur Andersen LLP, dated January 25, 2000, relating to the 1999 Financial Statements. 99.3 Management's Discussion and Analysis of Financial Condition and Results of Operations, dated January 25, 2000, relating to the 1999 Financial Statements. ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS (c) Exhibits SIGNATURE Pursuant to the requirements of the Securities and Exchange Act of 1934, Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. NORTHEAST UTILITIES By: /s/ John H. Forsgren ------------------------------- John H. Forsgren Executive Vice President and Chief Financial Officer Date: February 23, 2000 EX-23 2 CONSENTS OF EXPERTS AND COUNSEL Exhibit 23 to Form 8-K Report CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report included in this Form 8-K, into the Company's previously filed Registration Statements No. 33-55279 of The Connecticut Light and Power Company, No. 33-56537 of CL&P Capital, LP and No. 33-34622, No. 33-44814, No. 33-63023, No. 33-40156, No. 333-52413, No. 333-52415, and No. 333-85613 of Northeast Utilities. It should be noted that we have not audited any financial statements of the Company subsequent to December 31, 1999 or performed any audit procedures subsequent to the date of our report. /s/ ARTHUR ANDERSEN LLP Hartford, Connecticut February 25, 2000 EX-27 3
UT 0000072741 NORTHEAST UTILITIES AND SUBSIDIARIES 1,000 YEAR DEC-31-1999 DEC-31-1999 PER-BOOK 3,947,434 888,181 1,071,280 3,781,157 0 9,688,052 686,969 940,726 581,817 2,083,311 121,289 136,200 2,372,341 278,000 0 0 457,065 46,250 62,824 118,469 4,012,303 9,688,052 4,471,251 98,611 3,945,831 4,126,714 344,537 (106,187) 320,622 263,651 56,971 22,755 34,216 13,168 258,093 614,218 0.26 0.26
EX-99.1 4 1999 FINANCIAL STATEMENTS Exhibit 99.1 to Form 8-K Report NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Income
- --------------------------------------------------------------------------------------------- For the Years Ended December 31, - --------------------------------------------------------------------------------------------- (Thousands of Dollars, except share information) 1999 1998 1997 - --------------------------------------------------------------------------------------------- Operating Revenues................................. $ 4,471,251 $ 3,767,714 $ 3,834,806 ------------- ------------- ------------- Operating Expenses: Operation - Fuel, purchased and net interchange power...... 1,898,314 1,470,200 1,478,566 Other.......................................... 855,917 803,419 919,431 Maintenance........................................ 340,419 399,165 501,693 Depreciation....................................... 302,305 332,807 354,329 Amortization of regulatory assets, net............. 596,437 203,132 123,718 Federal and state income taxes..................... 180,883 82,332 12,650 Taxes other than income taxes...................... 261,353 251,932 253,637 Gain on sale of utility plant...................... (308,914) - - ------------- ------------- ------------- Total operating expenses..................... 4,126,714 3,542,987 3,644,024 ------------- ------------- ------------- Operating Income................................... 344,537 224,727 190,782 ------------- ------------- ------------- Other Income/(Loss): Equity in earnings of regional nuclear generating and transmission companies.................... 5,034 12,420 11,306 Nuclear unrecoverable costs ....................... (71,066) (143,239) - Other, net......................................... (30,855) (12,225) (31,185) Minority interest in loss of subsidiary............ (9,300) (9,300) (9,300) Income taxes....................................... 82,272 76,393 10,702 ------------- ------------- ------------- Other loss, net.............................. (23,915) (75,951) (18,477) ------------- ------------- ------------- Income before interest charges............... 320,622 148,776 172,305 ------------- ------------- ------------- Interest Charges: Interest on long-term debt......................... 258,093 273,824 282,095 Other interest..................................... 13,959 7,808 3,561 Deferred interest - nuclear plants................. (8,401) (12,543) (13,675) ------------- ------------- ------------- Interest charges, net........................ 263,651 269,089 271,981 ------------- ------------- ------------- Income/(loss) after interest charges......... 56,971 (120,313) (99,676) Preferred Dividends of Subsidiaries................ 22,755 26,440 30,286 ------------- ------------- ------------- Net Income/(Loss).................................. $ 34,216 $ (146,753) $ (129,962) ============= ============= ============= Earnings/(Loss) Per Common Share - Basic and Diluted $ 0.26 $ (1.12) $ (1.01) ============= ============= ============= Common Shares Outstanding (average)................ 131,415,126 130,549,760 129,567,708 ============= ============= ============= NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Comprehensive Income Net Income/(Loss).................................. $ 34,216 $ (146,753) $ (129,962) ------------- ------------- ------------- Other comprehensive income, net of tax: Foreign currency translation adjustments........... 1 - (499) Unrealized gains on securities..................... 118 2,019 - Minimum pension liability adjustments.............. - (613) - ------------- ------------- ------------- Other comprehensive income/(loss), net of tax.. 119 1,406 (499) ------------- ------------- ------------- Comprehensive Income/(Loss)........................ $ 34,335 $ (145,347) $ (130,461) ============= ============= =============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Balance Sheets
- ---------------------------------------------------------------------------------------- At December 31, - ---------------------------------------------------------------------------------------- (Thousands of Dollars) 1999 1998 - ---------------------------------------------------------------------------------------- Assets Utility Plant, at cost: Electric................................................ $ 9,185,272 $ 9,570,547 Other................................................... 226,002 195,325 ------------- ------------- 9,411,274 9,765,872 Less: Accumulated provision for depreciation............ 6,088,310 4,224,416 ------------- ------------- 3,322,964 5,541,456 Unamortized PSNH acquisition costs........................ 324,437 352,855 Construction work in progress............................. 177,504 143,159 Nuclear fuel, net......................................... 122,529 133,411 ------------- ------------- Total net utility plant.............................. 3,947,434 6,170,881 ------------- ------------- Other Property and Investments: Nuclear decommissioning trusts, at market................. 711,910 619,143 Investments in regional nuclear generating companies, at equity.................................... 81,503 85,791 Other, at cost............................................ 94,768 151,857 ------------- ------------- 888,181 856,791 ------------- ------------- Current Assets: Cash and cash equivalents................................. 255,154 136,155 Investments in securitizable assets....................... 107,620 182,118 Receivables, less accumulated provision for uncollectible accounts of $4,895 in 1999 and $2,416 in 1998........... 310,190 237,207 Unbilled revenues......................................... 75,728 42,145 Fuel, materials and supplies, at average cost............. 172,973 202,661 Recoverable energy costs, net of current portion.......... 73,721 67,181 Prepayments and other..................................... 75,894 68,087 ------------- ------------- 1,071,280 935,554 ------------- ------------- Deferred Charges: Regulatory assets......................................... 3,642,439 2,328,949 Unamortized debt expense.................................. 39,192 40,416 Other .................................................... 99,526 54,790 ------------- ------------- 3,781,157 2,424,155 ------------- ------------- Total Assets.............................................. $ 9,688,052 $ 10,387,381 ============= =============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Balance Sheets
- ---------------------------------------------------------------------------------------- At December 31, - ---------------------------------------------------------------------------------------- (Thousands of Dollars) 1999 1998 - ---------------------------------------------------------------------------------------- Capitalization and Liabilities Capitalization: Common shares, $5 par value - authorized 225,000,000 shares; 137,393,829 shares issued and 131,870,284 shares outstanding in 1999 and 137,031,264 shares issued and 130,954,740 shares outstanding in 1998....... $ 686,969 $ 685,156 Capital surplus, paid in.................................. 940,726 940,661 Deferred contribution plan - employee stock ownership plan.......................................... (127,725) (140,619) Retained earnings......................................... 581,817 560,769 Accumulated other comprehensive income.................... 1,524 1,405 ------------- ------------- Total common shareholders' equity.................... 2,083,311 2,047,372 Preferred stock not subject to mandatory redemption....... 136,200 136,200 Preferred stock subject to mandatory redemption........... 121,289 167,539 Long-term debt............................................ 2,372,341 3,282,138 ------------- ------------- Total capitalization................................. 4,713,141 5,633,249 ------------- ------------- Minority Interest in Consolidated Subsidiaries............ 100,000 100,000 ------------- ------------- Obligations Under Capital Leases.......................... 62,824 88,423 ------------- ------------- Current Liabilities: Notes payable to banks.................................... 278,000 30,000 Long-term debt and preferred stock - current portion...... 503,315 397,153 Obligations under capital leases - current portion........ 118,469 120,856 Accounts payable.......................................... 347,321 338,612 Accrued taxes............................................. 158,684 50,755 Accrued interest.......................................... 37,904 51,044 Other..................................................... 126,768 139,367 ------------- ------------- 1,570,461 1,127,787 ------------- ------------- Deferred Credits and Other Long-term Liabilities: Accumulated deferred income taxes......................... 1,688,114 1,848,694 Accumulated deferred investment tax credits............... 140,407 143,369 Decommissioning obligation - Millstone 1.................. 702,351 692,000 Deferred contractual obligations.......................... 358,387 418,760 Other..................................................... 352,367 335,099 ------------- ------------- 3,241,626 3,437,922 ------------- ------------- Total Capitalization and Liabilities...................... $ 9,688,052 $ 10,387,381 ============= =============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Shareholders' Equity
- ---------------------------------------------------------------------------------------- Accum- Deferred ulated Contribu- Other Capital tion Retained Compre- Common Surplus, Plan- Earnings hensive (Thousands of Dollars) Shares Paid In ESOP (a) Income Total - ---------------------------------------------------------------------------------------- Balance as of January 1, 1997................$680,260 $939,589 $(176,091)$ 869,618 $ 498 $2,313,874 -------------------------------------------------------- Net loss for 1997............. (129,962) (129,962) Cash dividends on common shares-$0.25 per share...... (32,134) (32,134) Issuance of 790,232 common shares, $5 par value........ 3,951 2,551 6,502 Allocation of benefits - ESOP. (12,238) 21,950 9,712 Capital stock expenses, net... 2,592 2,592 Other comprehensive income/(loss)............... (499) (499) -------------------------------------------------------- Balance as of December 31, 1997............. 684,211 932,494 (154,141) 707,522 (1) 2,170,085 -------------------------------------------------------- Net loss for 1998............. (146,753) (146,753) Issuance of 189,094 common shares, $5 par value........ 945 1,714 2,659 Allocation of benefits - ESOP. (4,769) 13,522 8,753 Unearned stock compensation... (537) (537) Capital stock expenses, net... 3,560 3,560 Gain on equity investment..... 8,140 8,140 Gain on repurchase of preferred stock............. 59 59 Other comprehensive income.... 1,406 1,406 -------------------------------------------------------- Balance as of December 31, 1998............. 685,156 940,661 (140,619) 560,769 1,405 2,047,372 -------------------------------------------------------- Net income for 1999........... 34,216 34,216 Cash dividends on common shares-$0.10 per share...... (13,168) (13,168) Issuance of 362,565 common shares, $5 par value........ 1,813 3,505 5,318 Allocation of benefits - ESOP. (3,053) 12,894 9,841 Unearned stock compensation... (1,194) (1,194) Capital stock expenses, net... 807 807 Other comprehensive income.... 119 119 -------------------------------------------------------- Balance as of December 31, 1999.............$686,969 $940,726 $(127,725)$ 581,817 $1,524 $2,083,311 ======================================================== (a) Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt agreements. These restrictions also limit the amount of retained earnings available for NU common dividends. At December 31, 1999, retained earnings available for payment of dividends totaled $158.5 million.
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Cash Flows
- ------------------------------------------------------------------------------------------------ For the Years Ended December 31, - ------------------------------------------------------------------------------------------------ (Thousands of Dollars) 1999 1998 1997 - ------------------------------------------------------------------------------------------------ Operating Activities: Income/(loss) after interest charges......................... $ 56,971 $(120,313) $ (99,676) Adjustments to reconcile to net cash provided by operating activities: Depreciation............................................... 302,305 332,807 354,329 Deferred income taxes and investment tax credits, net...... (183,356) 23,502 26,435 Amortization of regulatory assets, net..................... 596,437 203,132 123,718 Amortization of demand-side-management costs, net.......... 10,014 42,085 38,029 Amortization/(deferral) of recoverable energy costs........ 44,526 38,356 (54,102) Nuclear unrecoverable costs................................ 71,066 143,239 - Gain on sale of utility plant.............................. (308,914) - - Net other sources and (uses) of cash....................... (55,543) 55,399 (66,518) Changes in working capital: Receivables and unbilled revenues, net..................... (106,566) (27,553) 352,384 Fuel, materials and supplies............................... 29,688 10,060 (1,307) Accounts payable........................................... 8,709 (64,258) (104,269) Accrued taxes.............................................. 107,929 4,739 38,966 Investments in securitizable assets........................ 74,498 48,787 (230,905) Other working capital (excludes cash)...................... (33,546) (26,714) (36,464) ---------- ---------- ---------- Net cash flows provided by operating activities................ 614,218 663,268 340,620 ---------- ---------- ---------- Financing Activities: Issuance of common shares.................................... 5,318 2,659 6,502 Issuance of long-term debt................................... 200 275 260,000 Net increase/(decrease) in short-term debt................... 248,000 (20,000) 11,250 Reacquisitions and retirements of long-term debt............. (817,759) (269,555) (288,793) Reacquisitions and retirements of preferred stock............ (46,250) (62,211) (25,000) Cash dividends on preferred stock............................ (22,755) (26,440) (30,286) Cash dividends on common shares.............................. (13,168) - (32,134) ---------- ---------- ---------- Net cash flows used in financing activities.................... (646,414) (375,272) (98,461) ---------- ---------- ---------- Investing Activities: Investment in plant: Electric and other utility plant........................... (287,081) (217,009) (233,399) Nuclear fuel............................................... (42,471) (17,026) (6,852) ---------- ---------- ---------- Net cash flows used for investments in plant................. (329,552) (234,035) (240,251) Investment in nuclear decommissioning trusts................. (74,231) (75,551) (61,046) Investment in nonregulated assets............................ (23,542) - - Net proceeds from the sale of utility plant.................. 565,436 - - Other investment activities, net............................. 13,084 14,342 8,344 ---------- ---------- ---------- Net cash flows provided by/(used in) investing activities...... 151,195 (295,244) (292,953) ---------- ---------- ---------- Net increase/(decrease) in cash for the period................. 118,999 (7,248) (50,794) Cash and cash equivalents - beginning of period................ 136,155 143,403 194,197 ---------- ---------- ---------- Cash and cash equivalents - end of period...................... $ 255,154 $ 136,155 $ 143,403 ========== ========== ========== Supplemental Cash Flow Information: Cash paid/(refunded) during the year for: Interest, net of amounts capitalized......................... $ 266,823 $ 238,990 $ 291,335 ========== ========== ========== Income taxes................................................. $ 86,183 $ 19,454 $ (26,387) ========== ========== ========== Increase in obligations: Niantic Bay Fuel Trust and other capital leases.............. $ 5,865 $ 12,583 $ 3,475 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Capitalization At December 31, (Thousands of Dollars) 1999 1998 Common Shareholders' Equity........................................................ $ 2,083,311 $ 2,047,372 ------------ ------------ Cumulative Preferred Stock of Subsidiaries: $25 par value - authorized 36,600,000 shares at December 31, 1999 and 1998; 2,720,000 shares outstanding in 1999 and 3,780,000 shares outstanding in 1998 $50 par value - authorized 9,000,000 shares at December 31, 1999 and 1998; 4,314,774 shares outstanding in 1999 and 4,709,774 shares outstanding in 1998 $100 par value - authorized 1,000,000 shares at December 31, 1999 and 1998; 200,000 shares outstanding in 1999 and 1998 Current Current Shares Dividend Rates Redemption Price (a) Outstanding Not Subject to Mandatory Redemption: $50 par value - $1.90 to $3.28 $50.50 to $54.00 2,324,000......... 116,200 116,200 $100 par value - $7.72 $103.51 200,000......... 20,000 20,000 ------------ ------------ Total Preferred Stock Not Subject to Mandatory Redemption.......................................................... 136,200 136,200 ------------ ------------ Subject to Mandatory Redemption: (b) $25 par value - $1.90 to $2.65 $25.00 to $25.38 2,720,000......... 68,000 94,500 $50 par value - $2.65 to $3.615 $50.67 to $51.93 1,990,774......... 99,539 119,289 ------------ ------------ Total Preferred Stock Subject to Mandatory Redemption............................................................. 167,539 213,789 Less: Preferred Stock to be redeemed within one year......................................................... 46,250 46,250 ------------ ------------ Preferred Stock Subject to Mandatory Redemption, net........................................................ 121,289 167,539 ------------ ------------ Long-Term Debt: (c) First Mortgage Bonds - Maturity Interest Rates 1999 5.50% to 7.25%......................................................... - 254,000 2000 5.75% to 6.875%........................................................ 159,000 260,000 2001 7.375% to 7.875%....................................................... 220,000 220,000 2002 7.75% to 9.05%......................................................... 489,150 560,000 2004 6.125%................................................................. - 140,000 2019-2023 7.375% to 7.50%........................................................ 20,000 120,000 2024-2025 7.375% to 8.50%........................................................ 305,000 430,000 ------------ ------------ Total First Mortgage Bonds....................................................... 1,193,150 1,984,000 ------------ ------------ Other Long-Term Debt - Pollution Control Notes and Other Notes - (d) 2000 Adjustable Rate (e) and 7.67%.............................................................. 206,011 212,022 2005-2006 8.38% to 8.58%......................................................... 158,000 177,000 2013-2018 Adjustable Rate and 5.90%.............................................................. 33,400 33,400 2020 Adjustable Rate........................................................ 15,300 15,300 2021-2022 5.85% to 7.65% and Adjustable Rate........................................................ 552,485 552,485 2028 5.85% to 5.95%......................................................... 369,300 369,300 2031 Adjustable Rate........................................................ 62,000 62,000 ------------ ------------ Total Pollution Control Notes and Other Notes................................................................ 1,396,496 1,421,507 Fees and interest due for spent nuclear fuel disposal costs...................................................... 226,463 216,377 Other.............................................................................. 15,346 17,043 ------------ ------------ Total Other Long-Term Debt......................................................... 1,638,305 1,654,927 ------------ ------------ Unamortized premium and discount, net.................................................................... (2,049) (5,886) ------------ ------------ Total Long-Term Debt............................................................... 2,829,406 3,633,041 Less: Amounts due within one year................................................. 457,065 350,903 ------------ ------------ Long-Term Debt, net................................................................ 2,372,341 3,282,138 ------------ ------------ Total Capitalization............................................................... $ 4,713,141 $ 5,633,249 ============ ============
The accompanying notes are an integral part of these financial statements NORTHEAST UTILITIES AND SUBSIDIARIES Notes to Consolidated Statements of Capitalization (a) Each of these series is subject to certain refunding limitations for the first five years after issuance. Redemption prices reduce in future years. (b) Changes in Preferred Stock Subject to Mandatory Redemption: (Millions of Dollars) Balance at December 31, 1997................. $276.0 Reacquisitions and Retirements............. (62.2) Balance at December 31, 1998................. 213.8 Reacquisitions and Retirements............. (46.3) Balance at December 31, 1999................. $167.5 The minimum sinking fund requirements of the series subject each year to mandatory redemption aggregate $46.3 million each year in 2000 and 2001, $21.3 million in 2002, $7.7 million in 2003 and $5.3 million in 2004. In case of default on sinking fund payments, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If a subsidiary is in arrears in the payment of dividends on any outstanding shares of preferred stock, the subsidiary is prohibited from redeeming or purchasing less than all of the outstanding preferred stock. (c) Long-term debt maturities and cash sinking fund requirements, excluding fees and interest due for spent nuclear fuel disposal costs, on debt outstanding at December 31, 1999, for the years 2000 through 2004 are $457.1 million, $314 million, $374.6 million, $25.6 million, and $25.5 million, respectively. Essentially all utility plant of CL&P, PSNH, WMECO, and NAEC, is subject to the liens of each company's respective first mortgage bond indenture. NAEC's first mortgage bonds are also secured by payments made to NAEC by PSNH under the terms of two life-of-unit, full cost recovery contracts. CL&P and WMECO have secured $369.3 million of pollution control notes with second mortgage liens on Millstone 1, junior to the liens of their respective first mortgage bond indentures. CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) with bond insurance secured by the first mortgage bonds and a liquidity facility. Concurrent with the issuance of PSNH's Series A and B first mortgage bonds, PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the state of New Hampshire. Pursuant to these arrangements, the BFA issued seven series of PCRBs and loaned the proceeds to PSNH. At December 31, 1999 and 1998, $516.5 million of the PCRBs were outstanding. PSNH's obligation to repay each series of PCRBs is secured by the first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. For financial reporting purposes, these bonds would not be considered outstanding unless PSNH failed to meet its obligations under the PCRBs. (d) The average effective interest rates on the variable-rate pollution control notes ranged from 2.2 percent to 6.1 percent for 1999 and 3.1 percent to 5.6 percent for 1998. During 1998, $535 million of adjustable-rate debt was converted to fixed- rate debt at rates ranging from 5.85 percent to 6.0 percent. (e) Interest rate swaps effectively fix the interest rate of NAEC's $200 million variable-rate bank note at interest rates ranging from 5.81 percent to 6.07 percent. Consolidated Statements of Income Taxes For the Years Ended December 31, (Thousands of Dollars) 1999 1998 1997 The components of the federal and state income tax provisions charged to operations are: Current income taxes: Federal.................................. $ 248,012 $ (13,660) $ (22,760) State.................................... 33,955 (3,903) (1,727) ---------- ---------- ---------- Total current.............................. 281,967 (17,563) (24,487) ---------- ---------- ---------- Deferred income taxes, net: Federal.................................. (134,773) 51,913 46,871 State.................................... (28,789) (12,948) (10,841) ---------- ---------- ---------- Total deferred............................. (163,562) 38,965 36,030 ---------- ---------- ---------- Investment tax credits, net................ (19,794) (15,463) (9,595) ---------- ---------- ---------- Total income tax expense................... $ 98,611 $ 5,939 $ 1,948 ========== ========== ========== The components of total income tax expense are classified as follows: Income taxes charged to operating expenses............................... $ 180,883 $ 82,332 $ 12,650 Other income taxes....................... (82,272) (76,393) (10,702) ---------- ---------- ---------- Total income tax expense................... $ 98,611 $ 5,939 $ 1,948 ========== ========== ========== Deferred income taxes are comprised of the tax effects of temporary differences as follows: Deferred tax asset associated with net operating losses................... $ 14,801 $ 69,212 $ - Depreciation, leased nuclear fuel, settlement credits and disposal costs.. (4,580) 16,217 32,932 Regulatory deferral...................... (23,463) (26,786) 19,237 State net operating loss carryforward.... 7,777 1,150 (7,670) Regulatory disallowance.................. (30,719) (18,080) - Sale of fossil and hydroelectric generation assets...................... (125,807) - - Other.................................... (1,571) (2,748) (8,469) ---------- ---------- ---------- Deferred income taxes, net................. $(163,562) $ 38,965 $ 36,030 ========== ========== ========== A reconciliation between income tax expense and the expected tax expense at 35 percent of pretax income: Expected federal income tax................ $ 54,454 $ (40,031) $ (34,205) Tax effect of differences: Depreciation............................. 35,672 25,793 21,776 Amortization of regulatory assets........ 34,736 30,740 5,498 Amortization of PSNH acquisition costs... 9,946 17,301 31,298 Investment tax credit amortization....... (19,794) (15,463) (9,595) State income taxes, net of federal benefit................................ 3,358 (10,953) (8,169) Nondeductible penalties.................. 17 3,589 648 Adjustment for prior years' taxes........ (2,796) (7,338) (2,592) Employee stock ownership plan............ 1,166 (1,670) (4,648) Dividends received deduction............. (1,314) (3,218) (1,563) Adjustment to tax asset valuation allowance.............................. (23,129) 7,000 8,750 Merger related expenditures.............. 4,597 - - Other, net............................... 1,698 189 (5,250) --------- ---------- ---------- Total income tax expense $ 98,611 $ 5,939 $ 1,948 ========= ========== ========== The accompanying notes are in integral part of these financial statements. Notes to Consolidated Financial Statements 1. Summary of Significant Accounting Policies A. About Northeast Utilities Northeast Utilities (NU or the company) is the parent company of the Northeast Utilities system (NU system). Through its regulated utilities and unregulated energy service companies, the NU system serves in excess of 30 percent of New England's electric needs and is one of the 20 largest electric utility systems in the country as measured by revenues. The NU system's regulated utilities furnish franchised retail electric service in Connecticut, New Hampshire and western Massachusetts through three wholly owned subsidiaries: The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO). Another wholly owned subsidiary, North Atlantic Energy Corporation (NAEC), sells all of its entitlement to the capacity and output of the Seabrook Station (Seabrook) nuclear unit to PSNH under the terms of two life-of-unit, full cost recovery contracts (Seabrook Power Contracts). A fifth wholly owned subsidiary, Holyoke Water Power Company (HWP), also is engaged in the production and distribution of electric power. NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and the NU system is subject to the provisions of the 1935 Act. Arrangements among the NU system companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. The operating subsidiaries are subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions. NU Enterprises, Inc. (NUEI) is a wholly owned subsidiary of NU and acts as the holding company for NU's unregulated energy service companies. Northeast Generation Company (NGC) was formed to acquire generating facilities. Northeast Generation Services Company (NGS) was formed to provide services to the electric generation market as well as to large commercial and industrial customers in the Northeast. Select Energy, Inc. (Select Energy), HEC Inc. (HEC) and Mode 1 Communications, Inc. (Mode 1) engage in a variety of energy-related and telecommunications activities, as applicable, primarily in the unregulated energy retail and wholesale commodity, marketing and services fields. During 1999 and 1998, NUEI accounted for 13.6 percent and 1.4 percent of consolidated revenues, respectively. Several wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing, and other services to the NU system companies. Northeast Nuclear Energy Company acts as agent for the NU system companies and other New England utilities in operating the Millstone nuclear units. North Atlantic Energy Service Corporation has operational responsibility for Seabrook. Three other subsidiaries construct, acquire or lease some of the property and facilities used by the NU system companies. On October 13, 1999, NU and Consolidated Edison, Inc. (Con Edison) announced that they have agreed to a merger to combine the two companies. For further information, see Note 15, " Merger Agreement with Con Edison." On October 12, 1999, Yankee Energy System, Inc. shareholders approved the proposed merger with NU. On December 20, 1999, the Connecticut Department of Public Utility Control (DPUC) issued its final decision approving the merger. In January 2000, the SEC granted final approval of the merger. The transaction is expected to close in early March 2000. B. Presentation The consolidated financial statements of the NU system include the accounts of all subsidiaries. Intercompany transactions have been eliminated in consolidation. The preparation of financial statements in conformity with generally accepted accounting principles 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 years' data have been made to conform with the current year's presentation. C. New Accounting Standards The Financial Accounting Standards Board (FASB) has issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes accounting and reporting standards for derivative instruments and hedging activities. This statement will require derivative instruments utilized by the NU system companies to be recognized on the balance sheets as assets or liabilities at fair value. In June 1999, the FASB delayed the adoption date of SFAS No. 133 until January 1, 2001. Based on the derivative instruments which currently are being utilized by the NU system companies to hedge some of their interest rate risk and certain power contracts, there may be an impact on earnings upon adoption of SFAS No. 133 which management has not estimated at this time. D. Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock in four regional nuclear companies (Yankee Companies). The NU system's ownership interests in the Yankee Companies at December 31, 1999 and 1998, which are accounted for on the equity basis due to the NU system companies' ability to exercise significant influence over their operating and financial policies are 49 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 38.5 percent of the Yankee Atomic Electric Company (YAEC), 20 percent of the Maine Yankee Atomic Power Company (MYAPC), and 16 percent of the Vermont Yankee Nuclear Power Corporation (VYNPC). The NU system's total equity investment in the Yankee Companies at December 31, 1999 and 1998, is $81.5 million and $85.8 million, respectively. Each Yankee Company owns a single nuclear generating unit. However, VYNPC is the only unit still in operation at December 31, 1999. Millstone: CL&P and WMECO together own 100 percent of both Millstone 1, a 660 megawatt (MW) nuclear unit and Millstone 2, an 870 MW nuclear generating unit. CL&P, PSNH and WMECO together have a 68.02 percent joint ownership interest in Millstone 3, a 1,154 MW nuclear generating unit. The company expects to auction all three units as a single package in 2000, with a closing in 2001. Appropriate regulatory approvals will be required to complete the auction. Seabrook: CL&P and NAEC together have a 40.04 percent joint ownership interest in Seabrook, a 1,148 MW nuclear generating unit. NAEC sells all of its share of the power generated by Seabrook to PSNH under the Seabrook Power Contracts. CL&P and NAEC expect to auction their investment in Seabrook upon the resolution of the restructuring issues in the state of New Hampshire. Plant-in-service and the accumulated provision for depreciation for the NU system's share of Millstone 2 and 3 and Seabrook are as follows: At December 31, (Millions of Dollars) 1999 1998 Plant-in-service Millstone 2............................ $ 952.1 $ 936.8 Millstone 3............................ 2,414.9 2,407.4 Seabrook............................... 901.9 895.5 Accumulated provision for depreciation Millstone 2............................ $ 910.0 $ 379.6 Millstone 3............................ 2,220.5 765.9 Seabrook............................... 318.8 170.0 Hydro-Quebec: NU has a 22.66 percent equity ownership interest, totaling $16.5 million, in two companies that transmit electricity imported from the Hydro-Quebec system in Canada. E. Depreciation The provision for depreciation is calculated using the straight-line method based on the estimated remaining useful lives of depreciable utility plant- in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Except for major facilities, depreciation rates are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. The costs of closure and removal of nonnuclear facilities are accrued over the life of the plant as a component of depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.3 percent in 1999 and 1998 and 3.8 percent in 1997. At December 31, 1999 and 1998, the accumulated provision for depreciation included $91.5 million and $88.4 million, respectively, accrued for the cost of removal, net of salvage, for nonnuclear generation property. As a result of discontinuing the application of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," for CL&P's and WMECO's generation businesses, including CL&P's ownership interest in Seabrook, the company recorded a charge to accumulated depreciation for the nuclear plant in excess of fair market value in the amount of $2 billion, and a corresponding regulatory asset was created. F. Revenues Regulated utility revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission. Regulatory commissions also have authority over the terms and conditions of nontraditional rate-making arrangements. At the end of each accounting period, CL&P, PSNH and WMECO accrue a revenue estimate for the amount of energy delivered but unbilled. Revenues for NU's unregulated subsidiaries, primarily Select Energy, are recognized when the energy is delivered. G. PSNH Acquisition Costs PSNH acquisition costs represent the aggregate value placed by the 1989 rate agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in excess of the net book value of PSNH's non-Seabrook assets, plus the $700 million value assigned to Seabrook by the Rate Agreement as part of the bankruptcy resolution on June 5, 1992. The Rate Agreement provides for the recovery through rates, with a return, of the PSNH acquisition costs. The unrecovered balance was $324.4 million and $352.9 million at December 31, 1999 and 1998, respectively, and is being recovered ratably over a 20-year period ending May 1, 2011, in accordance with the Rate Agreement. Through December 31, 1999 and 1998, $668 million and $640 million, respectively, has been collected. H. Regulatory Accounting and Assets The accounting policies of the NU system operating companies and the accompanying consolidated financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71. As a result of final restructuring orders issued in 1999, CL&P and WMECO discontinued the application of SFAS No. 71 for the generation portion of their businesses. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, management continues to believe it is probable that the NU system operating companies will recover their investments in long-lived assets, including regulatory assets. In addition, all material regulatory assets are earning a return. The components of the NU system companies' regulatory assets are as follows: At December 31, (Millions of Dollars) 1999 1998 Recoverable nuclear costs............. $2,210.8 $ 576.3 Income taxes, net..................... 636.6 762.5 Unrecovered contractual obligations... 349.2 408.0 Recoverable energy costs, net......... 228.2 279.2 Deferred costs - nuclear plants....... 111.6 187.1 Other................................. 106.0 115.8 -------- -------- $3,642.4 $2,328.9 ======== ======== The restructuring orders in Connecticut and Massachusetts provide for the transmission and distribution business to continue to be cost-of-service based and also provide for a transition charge which recovers stranded costs, including the nuclear regulatory assets established below. As a result of discontinuing the application of SFAS No. 71 for CL&P's and WMECO's generation businesses, the company reclassified nuclear plant in excess of its estimated fair market value from plant to regulatory assets. As of December 31, 1999, both the CL&P unamortized balance ($1.38 billion) and the WMECO unamortized balance ($316.1 million) are classified as recoverable nuclear costs. Also included in that regulatory asset component for 1999 is $514.7 million, which includes Millstone 1 recoverable nuclear costs relating to the recoverable portion of the undepreciated plant and related assets ($145.7 million) and the decommissioning and closure obligation ($369 million). At this time, management continues to believe that the application of SFAS No. 71 for PSNH and NAEC remains appropriate. If the "Agreement to Settle PSNH Restructuring" (Settlement Agreement), as filed, is approved by the New Hampshire Public Utilities Commission (NHPUC) and implemented, then PSNH will discontinue the application of SFAS No. 71 for the generation portion of its business and record an after-tax write-off of $225 million. PSNH's transmission and distribution business will continue to be rate- regulated on a cost-of-service basis as the Settlement Agreement allows for the recovery of the remaining regulatory assets through that portion of the business. I. Income Taxes The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows: At December 31, (Millions of Dollars) 1999 1998 Accelerated depreciation and other plant-related differences.......... $1,388.0 $1,537.9 Net operating loss carryforwards........... - (33.4) Regulatory assets - income tax gross-up.... 241.2 370.0 Other...................................... 58.9 (25.8) -------- --------- $1,688.1 $1,848.7 ======== ========= As of December 31, 1999 and 1998, PSNH had an Investment Tax Credit carryforward of $23 million, which if unused, expires in 2004. J. Recoverable Energy Costs Energy Policy Act of 1992: Under the Energy Policy Act of 1992 (Energy Act), CL&P, PSNH, WMECO, and NAEC are assessed for their proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P, PSNH, WMECO, and NAEC are currently recovering these costs through rates. As of December 31, 1999 and 1998, the NU system's total D&D Assessment deferrals were $38.4 million and $57.5 million, respectively. CL&P: Through December 31, 1999, CL&P had an energy adjustment clause under which fuel prices above or below base-rate levels were charged to or credited to customers. At December 31, 1999 and 1998, recoverable energy costs included $62.6 million and $78.1 million, respectively, of costs previously deferred. Coincident with the start of restructuring, the fuel clause was terminated. The balance at December 31, 1999, has been recorded as a generation-related stranded cost and will be recovered through a transition charge mechanism. PSNH: The Rate Agreement includes a fuel and purchased-power adjustment clause (FPPAC) permitting PSNH to pass through to retail customers, for a 10-year period that began in May 1991, the retail portion of differences between the fuel and purchased-power costs assumed in the Rate Agreement and PSNH's actual costs, which include the costs related to the Seabrook Power Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are subject to a prudence review by the NHPUC. At December 31, 1999 and 1998, PSNH had $120.7 million and $156.3 million, respectively, of noncurrent recoverable energy costs deferred under the FPPAC. If the Settlement Agreement is approved, the FPPAC will be recovered through a transition charge. K. Deferred Costs - Nuclear Plants Under the Rate Agreement, the plant costs of Seabrook were phased into rates over a 7-year period beginning May 15, 1991. Total costs deferred under the phase-in plan were $288 million. This plan is accounted for in compliance with SFAS No. 92, "Regulated Enterprises - Accounting for Phase-In Plans." The costs will be fully recovered from PSNH's customers by May 2001. L. Unrecovered Contractual Obligations Under the terms of contracts with the Yankee Companies, the shareholder- sponsored companies are responsible for their proportionate share of the remaining costs of the units, including decommissioning. As management expects that the NU system companies will be allowed to recover these costs from their customers, the NU system companies have recorded regulatory assets, with corresponding obligations, on their respective balance sheets. M. Interest Rate Risk Management Instruments The NU system utilizes market risk management instruments to hedge well-defined risks associated with variable interest rates. To qualify for hedge treatment, the underlying hedged item must expose the company to risks associated with market fluctuations and the market risk management instrument used must be designated as a hedge and must reduce the NU system's exposure to market fluctuations throughout the period. Amounts receivable or payable under interest rate risk management instruments are accrued and offset against interest expense. N. Cash and Cash Equivalents Cash and cash equivalents includes cash on hand and short-term cash investments which are highly liquid in nature and have original maturities of three months or less. 2. Nuclear Decommissioning and Plant Closure Costs Millstone and Seabrook: The NU system operating nuclear power plants, Millstone 2 and 3 and Seabrook, have service lives that are expected to end during the years 2015 through 2026, and upon retirement, must be decommissioned. Millstone 1's expected service life was to end in 2010, however, in July 1998, restart activities were discontinued and preparations for decommissioning the unit began. Current decommissioning studies conclude that complete and immediate dismantlement as soon as practical after retirement continues to be the most viable and economic method of decommissioning a unit. These studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology, and inflation. Changes in requirements or technology, the timing of funding or dismantling or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. CL&P, PSNH and WMECO attempt to recover sufficient amounts through their allowed rates to cover their expected decommissioning costs. The estimated cost of decommissioning Millstone 2, in year end 1999 dollars is $413.4 million. The NU system's ownership share of the estimated cost of decommissioning Millstone 3 and Seabrook in year end 1999 dollars, is $421.3 million and $226.2 million, respectively. Nuclear decommissioning costs are accrued over the expected service lives of the units and are included in depreciation expense. Nuclear decommissioning expenses for these units amounted to $30.6 million in 1999, $27.9 million in 1998 and $28.6 million in 1997. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation. Through December 31, 1999 and 1998, total decommissioning expenses of $260.6 million and $229.7 million, respectively, have been collected from customers and are reflected in the accumulated provision for depreciation. A Post-Shutdown Decommissioning Activities Report for Millstone 1 was filed with the Nuclear Regulatory Commission (NRC) in June 1999 which outlines decommissioning activities, and costs, and supports the obligation recorded by the company. Nuclear decommissioning expenses for Millstone 1 were $25.7 million in 1999, $19.8 million in 1998 and $20.2 million in 1997. External decommissioning trusts have been established for the costs of decommissioning the Millstone units. Payments for the NU system's ownership share of the cost of decommissioning Seabrook are paid to an independent decommissioning financing fund managed by the state of New Hampshire. Funding of the estimated decommissioning costs assumes levelized collections for the Millstone units and escalated collections for Seabrook and after-tax earnings on the Millstone and Seabrook decommissioning funds of 5.5 percent and 6.5 percent, respectively. As of December 31, 1999 and 1998, CL&P, PSNH and WMECO collected a total of $260.6 million and $229.7 million, respectively, through rates toward the future decommissioning costs of their shares of Millstone 2 and 3 and Seabrook, of which $239.7 million in 1999 and $209.9 million in 1998 have been transferred to external decommissioning trusts. Earnings on the decommissioning trusts increase the decommissioning trust balances and the accumulated reserves for depreciation. Unrealized gains and losses associated with the decommissioning trusts and financing funds also impact the balance of the trusts and the accumulated reserve for depreciation. The fair values of the amounts in the external decommissioning trusts were $415.9 million and $349.9 million at December 31, 1999 and 1998, respectively. Yankee Companies: VYNPC owns and operates a nuclear generating unit with a service life that is expected to end in 2012. The NU system's ownership share of estimated costs, in year end 1999 dollars, of decommissioning this unit is $68.6 million. On October 15, 1999, VYNPC agreed to sell the unit for $22 million to an unaffiliated company. Among other commitments, the acquiring company agreed to assume the decommissioning cost of the unit after it is taken out of service, and the VYNPC owners have agreed to fund the uncollected decommissioning cost to a negotiated amount at the time of the closing of the sale. As of December 31, 1999 and 1998, NU's remaining estimated obligation, including decommissioning for the units owned by CYAPC, YAEC and MYAPC, which have been shut down was $358.4 million and $418.8 million, respectively. 3. Short-Term Debt Limits: The amount of short-term borrowings that may be incurred by NU and the NU system operating companies is subject to periodic approval by either the SEC under the 1935 Act or by the respective state regulators. SEC authorization allowed NU, CL&P, WMECO, and NAEC, as of January 1, 1999, to incur total short-term borrowings up to a maximum of $400 million, $375 million, $250 million, and $60 million, respectively. In addition, the charters of CL&P and WMECO contain preferred stock provisions restricting the amount of unsecured debt those companies may incur. As of December 31, 1999, CL&P's and WMECO's charters permit CL&P and WMECO to incur $322 million and $132 million, respectively, of unsecured debt. PSNH is authorized under a NHPUC order to incur short-term borrowings up to a maximum of $68.3 million. Credit Agreements: On November 19, 1999, CL&P and WMECO entered into a new 364-day revolving credit facility for $500 million, replacing the previous $313.75 million facility which was to expire on November 21, 1999. The revolving credit facility will be used to bridge gaps in working capital and provide short-term liquidity. CL&P and WMECO may draw up to $300 million and $200 million, respectively, under the facility which is secured by second mortgages on Millstone 2 and 3. Unless extended, the new credit facility will expire on November 17, 2000. At December 31, 1999 and 1998, there were $213 million and $30 million, respectively, in borrowings under these facilities. To support the working capital needs of NU and its unregulated subsidiaries, NU replaced its $25 million 364-day revolving credit facility which was to expire on November 21, 1999, with a new 364-day unsecured revolving credit facility (NU Credit Agreement) on November 19, 1999. This new facility provides a total commitment of $350 million which is available subject to two overlapping sub-limits. First, subject to the notional amount of any letters of credit outstanding, amounts up to $200 million are available for advances. Second, subject to the advances outstanding, letters of credit may be issued in notional amounts up to $250 million. Unless extended, this credit facility will expire on November 17, 2000. As of December 31, 1999 and 1998, there were $65 million and no borrowings under the NU Credit Agreement and the previous credit facility, respectively. In regard to credit support, NU had $29 million in letters of credit issued under this agreement as of December 31, 1999. In addition, NU provides credit assurance in the form of guarantees, letters of credit, performance guarantees and other assurances for the financial performance obligations of certain of its unregulated subsidiaries. NU currently has authorization from the SEC to provide up to $500 million of guarantees, but is limited under certain loan agreements to $350 million of such arrangements without creditor approval. As of December 31, 1999, NU had provided approximately $190 million of such credit assurances. Under the credit agreements discussed above, the respective borrowers may borrow at fixed or variable rates plus an applicable margin based upon the companies' most senior secured debt as rated by the lower of Standard and Poor's or Moody's Investors Service (Moody's). The weighted average interest rate on the NU system companies' notes payable to banks outstanding on December 31, 1999 and 1998, was 7.928 percent and 6.53 percent, respectively. Maturities of short-term debt obligations were for periods of three months or less. These credit agreements provide that the parties to these agreements must comply with certain financial and nonfinancial covenants as are customarily included in such agreements, including, but not limited to, common equity ratios, interest coverage ratios and dividend payment restrictions. 4. Leases CL&P and WMECO finance their nuclear fuel for Millstone 2 and their respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement. This capital lease agreement has an expiration date of June 1, 2040. At December 31, 1999 and 1998, the present value of the capital lease obligation to the NBFT was $157 million and $178.7 million, respectively. In connection with the planned nuclear divestiture, CL&P and WMECO anticipate that the NBFT capital lease agreement will be terminated and the NBFT's obligation under the $180 million Series G Intermediate Term Note agreement will be assigned to CL&P and WMECO. CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel consumed in the reactors based on a units-of-production method at rates which reflect estimated kilowatt-hours of energy provided plus financing costs associated with the fuel in the reactors. Upon permanent discharge from the reactors, ownership of the nuclear fuel transfers to CL&P and WMECO. The NU system companies also have entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, nuclear control room simulators, and office space. The provisions of these lease agreements generally provide for renewal options. Capital lease rental payments charged to operating expense were $20.8 million in 1999, $31 million in 1998 and $19 million in 1997. Interest included in capital lease rental payments was $13.7 million in 1999, $18.3 million in 1998 and $13.6 million in 1997. Operating lease rental payments charged to expense were $7.5 million in 1999, $15.7 million in 1998 and $17.3 million in 1997. Future minimum rental payments, excluding annual nuclear fuel lease payments and executory costs, such as property taxes, state use taxes, insurance and maintenance, under long-term noncancelable leases, as of December 31, 1999 are: (Millions of Dollars) Year Capital Leases Operating Leases 2000............................... $ 7.4 $ 24.4 2001............................... 4.9 22.6 2002............................... 3.1 19.0 2003............................... 3.1 15.5 2004............................... 3.0 13.6 After 2004......................... 30.6 26.9 ------ ------- Future minimum lease payments...... 52.1 $ 122.0 ======= Less amount representing interest.. 27.8 ------ Present value of future minimum lease payments for other than nuclear fuel..................... 24.3 Present value of future nuclear fuel lease payments.............. 157.0 ------ Present value of future minimum lease payments........... $181.3 ====== 5. Employee Benefits A. Pension Benefits and Postretirement Benefits Other Than Pensions The NU system companies participate in a uniform noncontributory defined benefit retirement plan covering substantially all regular NU system employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. The total pension credit, part of which was credited to utility plant, was $54.4 million in 1999, $44.1 million in 1998 and $22.5 million in 1997. Currently, the NU system companies annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code (the Code). The NU system companies also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. These benefits are available for employees retiring from the NU system who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the future estimated work life of the employee. The NU system companies annually fund postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible under the Code. Pension and trust assets are invested primarily in domestic and international equity securities and bonds. The following table represents information on the plans' benefit obligation, fair value of plan assets, and the respective plans' funded status: At December 31, Pension Benefits Postretirement Benefits (Millions of Dollars) 1999 1998 1999 1998 Change in benefit obligation Benefit obligation at beginning of year............$(1,479.2) $(1,392.8) $(305.2) $(286.0) Service cost................... (43.7) (37.4) (7.6) (6.6) Interest cost.................. (106.3) (96.8) (21.8) (20.9) Plan amendment................. (79.6) - - - Transfers...................... - 8.5 - - Actuarial gain/(loss).......... 133.8 (37.7) (1.3) (16.1) Benefits paid.................. 78.3 77.0 28.9 24.4 Settlements.................... (19.9) - 0.2 - ---------- ---------- -------- -------- Benefit obligation at end of year..................$(1,516.6) $(1,479.2) $(306.8) $(305.2) ========== ========== ======== ======== Change in plan assets Fair value of plan assets at beginning of year............$ 2,098.0 $ 1,919.4 $ 151.2 $ 129.4 Actual return on plan assets... 310.5 264.7 18.7 17.4 Employer contribution.......... - - 29.7 28.8 Benefits paid.................. (78.3) (77.0) (28.9) (24.4) Transfers...................... - (9.1) - - ---------- ---------- -------- -------- Fair value of plan assets at end of year..................$ 2,330.2 $ 2,098.0 $ 170.7 $ 151.2 ========== ========== ======== ======== Funded status at December 31...$ 813.6 $ 618.8 $(136.1) $(154.0) Unrecognized transition (asset)/obligation........... (7.4) (9.0) 196.6 211.9 Unrecognized prior service cost......................... 99.2 27.6 - - Unrecognized net gain.......... (904.7) (670.4) (60.4) (57.9) ---------- ---------- -------- -------- Prepaid/(accrued) benefit cost.$ 0.7 $ (33.0) $ 0.1 $ - ========== ========== ======== ======== The following actuarial assumptions were used in calculating the plans' year end funded status: At December 31, Pension Benefits Postretirement Benefits 1999 1998 1999 1998 Discount rate................... 7.75% 7.00% 7.75% 7.00% Compensation/progression rate... 4.75 4.25 4.75 4.25 Health care cost trend rate (a). N/A N/A 5.57 5.22 (a) The annual per capita cost of covered health care benefits was assumed to decrease to 4.9 percent by 2001. The components of net periodic benefit cost are: For the Years Ended December 31, Pension Benefits Postretirement Benefits (Millions of Dollars) 1999 1998 1997 1999 1998 1997 Service cost............ $ 43.7 $ 37.4 $ 34.9 $ 7.6 $ 6.6 $ 5.7 Interest cost........... 106.3 96.8 98.6 21.8 20.9 20.6 Expected return on plan assets........... (175.5) (153.2) (135.1) (11.7) (9.9) (8.1) Amortization of unrecognized net transition (asset)/ obligation............ (1.5) (1.5) (1.5) 15.1 15.1 15.1 Amortization of prior service cost.......... 7.9 2.1 2.1 - - - Amortization of actuarial gain........ (33.5) (25.7) (18.9) - - - Other amortization, net. - - - (3.1) (3.8) (5.0) Settlements............. (1.8) - (2.6) - - - ------- -------- -------- ------- ------ ------- Net periodic benefit (credit)/cost........ $(54.4) $ (44.1) $ (22.5) $ 29.7 $28.9 $ 28.3 ======= ======== ======== ======= ====== ======= For calculating pension and postretirement benefit costs, the following assumptions were used: For the Years Ended December 31, Pension Benefits Postretirement Benefits 1999 1998 1997 1999 1998 1997 Discount rate........... 7.00% 7.25% 7.75% 7.00% 7.25% 7.75% Expected long-term rate of return........ 9.50 9.50 9.25 N/A N/A N/A Compensation/ progression rate...... 4.25 4.25 4.75 4.25 4.25 4.75 Long-term rate of return - Health assets, net of tax........ N/A N/A N/A 7.50 7.75 7.50 Life assets......... N/A N/A N/A 9.50 9.50 9.25 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects: One Percentage One Percentage (Millions of Dollars) Point Increase Point Decrease Effect on total service and interest cost components......... $ 1.4 $ (1.4) Effect on postretirement benefit obligation............... $16.4 $(16.1) The trust holding the health plan assets is subject to federal income taxes. B. 401(k) Savings Plan NU maintains a 401(k) Savings Plan for substantially all NU system employees. This savings plan provides for employee contributions up to specified limits. NU matches employee contributions up to a maximum of 3 percent of eligible compensation with cash and NU stock. The matching contributions made by NU were $13.8 million for 1999, $13.2 million for 1998 and $12 million for 1997. C. ESOP NU maintains an Employee Stock Ownership Plan (ESOP) for purposes of allocating shares to employees participating in the NU system's 401(k) Savings Plan. Under this arrangement, NU issued unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of which were lent to the ESOP trust for the purchase of 10.8 million newly issued NU common shares (ESOP Shares). The ESOP trust is obligated to make principal and interest payments on the ESOP notes at the same rate that ESOP Shares are allocated to employees. NU makes annual contributions to the ESOP equal to the ESOP's debt service, less dividends received by the ESOP. All dividends received by the ESOP on unallocated shares are used to pay debt service and are not considered dividends for financial reporting purposes. During the fourth quarter of 1999, NU paid a 10 cent per share dividend. During 1998, there were no dividends paid on NU stock. In 1999 and 1998, the ESOP trust issued 556,978 and 584,107 of NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to employees. As of December 31, 1999 and 1998, the total allocated ESOP shares were 5,281,836 and 4,724,858, respectively, and total unallocated ESOP shares were 5,518,349 and 6,075,327, respectively. The fair market value of unallocated ESOP shares as of December 31, 1999 and 1998, was $113.5 million and $97.2 million, respectively. D. Stock-Based Compensation Employee Stock Purchase Plan (ESPP): Since July 1998, the NU system has maintained an ESPP for all eligible employees. Under the ESPP, shares of NU common stock may be purchased at 6-month intervals at 85 percent of the lower of the price on the first or last day of each 6-month period. Employees may purchase shares having a value not exceeding 25 percent of their compensation at the beginning of the purchase period. During 1999 and 1998, employees purchased 253,853 and 129,471 shares, respectively, at discounted prices ranging from $13.76 to $14.93 per share in 1999 and $13.60 per share in 1998. At December 31, 1999 and 1998, 1,616,676 and 1,870,529 shares remained reserved for future issuance under the ESPP, respectively. Incentive Plans: The NU system has long-term incentive plans authorizing various types of share-based awards, including stock options, to be made to eligible employees and board members. The exercise price of stock options, as set at the time of grant, is equal to the fair market value per share at the date of grant. Under the Northeast Utilities Incentive Plan (Incentive Plan), the number of shares which may be utilized for awards granted during a given calendar year may not exceed one percent of the total number of shares of NU common stock outstanding as of the first day of that calendar year. Stock option transactions for 1997, 1998 and 1999 are as follows: Exercise Price Per Share Weighted Options Range Average Outstanding December 31, 1996... - $ - $ - Granted......................... 500,000 $9.625 $ 9.625 ---------- Outstanding December 31, 1997... 500,000 $9.625 $ 9.625 Granted......................... 741,273 $14.875 - $16.8125 $16.178 Forfeited....................... (7,595) $16.3125 $16.3125 ---------- Outstanding December 31, 1998... 1,233,678 $ 9.625 - $16.8125 $13.5213 Granted......................... 644,123 $14.9375 - $21.125 $15.2514 Exercised....................... (19,368) $16.3125 - $16.8125 $16.3986 Forfeited....................... (32,177) $14.9375 - $16.3125 $15.8714 ---------- Outstanding December 31, 1999... 1,826,256 $ 9.625 - $21.125 $14.0585 ========== Exercisable December 31, 1997... - $ - $ - Exercisable December 31, 1998... 232,936 $14.875 - $16.8125 $16.2972 Exercisable December 31, 1999... 711,787 $ 9.625 - $21.125 $14.0102 The vesting schedule for the options granted in 1997 is 50 percent after two years, 75 percent after three years and the total award after four years. The vesting schedule for the options granted in 1998 is one-third upon grant, two-thirds after one year and the total award after two years. The options that were granted in 1999 vest ratably over three years from the date of grant. Also under the Incentive Plan, the NU system awarded 91,120 and 49,973 of restricted shares in 1999 and 1998, respectively. These shares have the same vesting schedule as the options granted under the Incentive Plan. During 1997, certain key officers were awarded restricted stock totaling 25,700 shares which vest ratably over three years from the date of grant. The NU system has also made several small grants of restricted stock and other incentive-based stock compensation. During 1999, 1998 and 1997, $2.2 million, $0.8 million and $0.3 million, respectively, was expensed for stock-based compensation. Had compensation cost been determined for the ESPP and the incentive plan stock options under the fair value method as opposed to the intrinsic value method followed by the NU system, net income/(loss) and net income/(loss) per share would have been as follows: (Millions of Dollars, except per share amounts) 1999 1998 1997 Net income/(loss)....................... $29.6 $(149.1) $(130.0) Basic income/(loss) per share........... $0.23 $ (1.14) $ (1.01) Diluted income/(loss) per share......... $0.22 $ (1.14) $ (1.01) The fair value of each stock option grant has been estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions: 1999 1998 1997 Risk-free interest rate................. 5.69% 5.82% 6.41% Expected life........................... 10 years 10 years 10 years Expected volatility..................... 36.21% 35.05% 31.89% Expected dividend yield................. 1.89% 5.46% 7.42% The weighted average grant date fair values of options granted during 1999, 1998 and 1997 were $6.79, $3.98 and $1.68, respectively. As of December 31, 1999, the weighted average remaining contractual life for those options outstanding is 8.47 years. 6. Sale of Customer Receivables As of December 31, 1999 and 1998, CL&P had sold accounts receivable of $170 million and $105 million, respectively, to a third-party purchaser with limited recourse through the CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. In addition, at December 31, 1999 and 1998, $22.5 million and $11.6 million, respectively, of assets was designated as collateral under the agreement with CRC. On June 30, 1999, WMECO terminated its $40 million accounts receivable program with its respective sponsor. At December 31, 1998, WMECO had sold accounts receivable of $20 million to a third-party purchaser. Concentrations of credit risk to the purchaser under the company's agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. 7. Commitments and Contingencies A. Restructuring Connecticut: During 1999, restructuring orders were issued by the DPUC which required CL&P to discontinue the application of SFAS No. 71 to the generation portion of its business and allowed for the recovery of the majority of its stranded costs. Stranded costs including regulatory assets will be collected through a transition charge through 2026. The restructuring orders also allowed for securitization of CL&P's nonnuclear regulatory assets and the costs to buyout or buydown the various purchased-power contracts. Securitization is the process of monetizing stranded costs through the sale of nonrecourse debt securities by a special purpose entity, collateralized by CL&P's interests in its stranded cost recoveries. On December 15, 1999, the DPUC issued a supplemental decision approving the components of CL&P's rates for standard offer service commencing on January 1, 2000. The DPUC also approved an interim nuclear capital recovery mechanism for the period from January 1, 2000, until the nuclear units are sold at auction. In approving the rates, the DPUC denied recovery of most of the capital additions made to Millstone 2 and 3 subsequent to June 30, 1997, which the company has or will expend to maintain those plants in a safe and efficient condition or to maintain their auction value. If implemented as approved, the company would not recover a significant portion of the capital additions which have been or are expected to be incurred subsequent to July 1, 1997, until the plants are sold in 2001. On December 29, 1999, CL&P filed with the DPUC a petition for reconsideration of this portion of the order. The DPUC has agreed to reopen the docket to consider CL&P's petition. Management believes the restructuring legislation provides for the recovery of these prudently incurred expenditures. If CL&P is unsuccessful in favorably resolving this contingency, an impairment loss of $50 million would be recorded. Massachusetts: In 1999, restructuring orders required WMECO to discontinue the application of SFAS No. 71 for the generation portion of its business. In these restructuring orders, WMECO was allowed to recover the majority of its stranded costs through a transition charge over the 12-year transition period beginning March 1, 1998. The decision instructed WMECO to work with the Massachusetts attorney general regarding the recovery of nuclear capital additions made after July 1, 1991. The decision also concluded that the company's deferred fuel balance should be included as part of the company's outstanding generating unit performance proceedings and not as part of the transition charge. Management believes that these costs are recoverable and that there will not be an impact on the results of operations. Nuclear Generation Assets Auction: In September 1999, NU announced that the Millstone nuclear generation assets of CL&P and WMECO will be put up for auction as soon as practical. On November 8, 1999, CL&P filed its divestiture plan for the Millstone units with the DPUC. The auction is expected to begin in early 2000, provided all regulatory approvals have been met, with a successful bidder chosen by mid 2000 and a closing in 2001. No NU system company will participate as a bidder in the auction process. Management expects to recover all of its nuclear stranded costs through the net proceeds of generation asset sales and through billing a transition charge to retail customers. New Hampshire: In August 1999, NU, PSNH and the state of New Hampshire signed a Settlement Agreement intended to settle a number of pending regulatory and court proceedings related to PSNH. Parties to the agreement included the governor of New Hampshire, the Governor's Office of Energy and Community Service, the New Hampshire attorney general, certain members of the staff of the NHPUC, PSNH and NU. The Settlement Agreement was submitted to the NHPUC on August 2, 1999, and is awaiting approval. If approved by the NHPUC, the Settlement Agreement would resolve 11 NHPUC dockets and PSNH's federal lawsuit which had enjoined the state of New Hampshire from implementing its restructuring legislation, would require PSNH to write off $225 million after- tax of its stranded costs and would allow for the recovery of the remaining amount. Also, implementation of the Settlement Agreement is contingent upon the issuance of $725 million in rate reduction bonds (securitization). Issuance of the rate reduction bonds requires the initial approval of the NHPUC and final approval from the New Hampshire Legislature via enactment of appropriate legislation. Other approvals are also required from various federal and state regulatory agencies and financial lenders. Under the terms of the Settlement Agreement, on the effective date, PSNH's rates will be reduced from current levels by an average of 18.3 percent. Due to the number of approvals required and still pending to implement the Settlement Agreement, management continues to believe the application of SFAS No. 71 is appropriate for PSNH at this time. The Settlement Agreement also requires PSNH to sell its generation assets and certain power contracts, including PSNH's current purchased-power contract with NAEC for the output from Seabrook. The net proceeds from all sales will be used to recover a portion of PSNH's stranded costs. The sales would be accomplished through an auction process subject to approval by the NHPUC. Following the divestiture, the transmission and distribution portion of the business will continue to be cost-of-service based. Phase I of the proceeding regarding the Settlement Agreement allowed proponents to provide sufficient record for the NHPUC to compare the Settlement Agreement to a range of reasonable outcomes in the other associated dockets. The NHPUC also determined within the testimony of Phase I that the Con Edison merger is relevant to the Settlement Agreement and intervening parties should have discovery in Phase II to evaluate the impact of the merger on the Settlement Agreement. Phase II allowed opponents to file testimony concerning the Settlement Agreement and then allowed proponents to conduct discovery and file rebuttal testimony. A decision on the Settlement Agreement is expected in the first quarter of 2000. B. Nuclear Litigation The non-NU joint owners of Millstone 3 have filed demands for arbitration with CL&P, WMECO and PSNH as well as lawsuits in Massachusetts Superior Court against NU and its current and former trustees related to the companies' operation of Millstone 3. During 1999, NU and these subsidiaries agreed in principle to settle with certain of the joint owners, who own 58 percent of the non-NU ownership of Millstone 3. The settlements provide for the payment to the claimants of $36.4 million and certain contingent payments. Arbitration and litigation claims remain outstanding for the remaining joint owners who have not agreed to settle. Management cannot estimate the potential outcome of the arbitration and litigation for the nonsettled joint owners, therefore, no liability has been established as of December 31, 1999. C. Environmental Matters The NU system is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of our environment. As such, the NU system has an active environmental auditing and training program and believes it is in compliance with the current laws and regulations. However, the normal course of operations may necessarily involve activities and substances that expose the NU system to potential liabilities of which management cannot determine the outcome. Additionally, management cannot determine the outcome for liabilities that may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Management does not believe, however, that this will have a material impact on the NU system's financial statements. Based upon currently available information for the estimated remediation costs as of December 31, 1999 and 1998, the liability recorded by the NU system for its estimated environmental remediation costs amounted to $24.8 million and $21.5 million, respectively. D. Spent Nuclear Fuel Disposal Costs Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO, and NAEC must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. Fees for nuclear fuel burned on or after April 7, 1983, are billed currently to customers and paid to the DOE on a quarterly basis. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full liability and payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. As of December 31, 1999 and 1998, fees due to the DOE for the disposal of Prior Period Fuel were $226.5 million and $216.4 million, respectively, including interest costs of $144.3 million and $134 million, respectively. E. Nuclear Insurance Contingencies Insurance policies covering the NU system's nuclear facilities have been purchased for the primary cost of repair, replacement or decontamination of utility property, certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement or decontamination or premature decommissioning of utility property. The NU system is subject to retroactive assessments if losses under those policies exceed the accumulated funds available to the insurer. The maximum potential assessments with respect to losses arising during the current policy year for the primary property insurance program, the replacement power policies and the excess property damage policies are $11 million, $6.2 million and $15 million, respectively. In addition, insurance has been purchased in the aggregate amount of $200 million on an industry basis for coverage of worker claims. Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third-party liability indemnification program, the NU system could be assessed liabilities in proportion to its ownership interest in each of its nuclear units up to $83.9 million. The NU system's payment of this assessment would be limited to, in proportion to its ownership interest in each of its nuclear units, $10 million in any one year per nuclear unit. In addition, if the sum of all claims and costs from any one nuclear incident exceeds the maximum amount of financial protection, the NU system would be subject to an additional 5 percent or $4.2 million liability, in proportion to its ownership interests in each of its nuclear units. Based upon its ownership interests in the Millstone units and in Seabrook, the NU system's maximum liability, including any additional assessments, would be $271 million per incident, of which payments would be limited to $30.8 million per year. In addition, through purchased-power contracts with VYNPC, the NU system would be responsible for up to an additional assessment of $14.1 million per incident, of which payments would be limited to $1.6 million per year. F. Construction Program The NU system companies currently forecast construction expenditures of $1.8 billion for the years 2000-2004, including $309.7 million for 2000. The NU system companies estimate that nuclear fuel requirements, including nuclear fuel financed through the NBFT, will be $217.8 million for the years 2000-2003, including $74.2 million for 2000. G. Long-Term Contractual Arrangements Yankee Companies: The NU system companies relied on VYNPC for 1.5 percent of their capacity under long-term contracts. Under the terms of their agreements, the NU system companies paid their ownership (or entitlement) shares of costs, which included depreciation, operation and maintenance (O&M) expenses, taxes, the estimated cost of decommissioning, and a return on invested capital. These costs were recorded as purchased-power expenses and recovered through the companies' rates. The total cost of purchases under contracts with VYNPC amounted to $29.2 million in 1999, $27.3 million in 1998 and $24.2 million in 1997. VYNPC has agreed to sell its nuclear unit. Upon completion of the sale, this long-term contract will be terminated. Nonutility Generators (NUGs): CL&P, PSNH and WMECO have entered into various arrangements for the purchase of capacity and energy from NUGs. For the years ended December 31, 1999 and 1998, 13 percent and for the year ended December 31, 1997, 14 percent, of NU system electricity requirements were met by NUGs. The total cost of purchases under these arrangements amounted to $461.8 million in 1999, $459.7 million in 1998 and $447.6 million in 1997. The company is in the process of renegotiating the terms of these contracts through either a contract buydown or buyout. The company expects any payments to the NUGs as a result of these renegotiations to be recovered from the company's customers. Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO, and HWP have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO, and HWP are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual O&M expenses and capital costs of those facilities. New Hampshire Electric Cooperative (NHEC): Previously, PSNH entered into a buy-back agreement to purchase the capacity and energy of the NHEC share of Seabrook and to pay all of NHEC's Seabrook costs for a 10-year period, which began on July 1, 1990. The total cost of purchases under this agreement was $33 million in 1999, $29.7 million in 1998 and $23.4 million in 1997. These costs are recoverable through the FPPAC. Effective January 1, 2000, the buy-back agreement was terminated. Estimated Annual Costs: The estimated annual costs of the NU system's significant long-term contractual arrangements, absent the effects of any contract terminations or buydowns are as follows: (Millions of Dollars) 2000 2001 2002 2003 2004 VYNPC....................... $ 24.1 $ 21.8 $ 21.9 $ 21.5 $ 21.0 NUGs........................ 472.6 480.2 489.2 500.1 487.3 Hydro-Quebec................ 31.3 30.3 29.6 28.7 27.8 Select Energy: Select Energy maintains long-term agreements to purchase both wholesale and retail energy in the normal course of business. The notional amount of these purchase contracts is $3.1 billion at December 31, 1999. These contracts extend through 2004 as follows: (Millions of Dollars) Year 2000...................... $1,271 2001...................... 638 2002...................... 573 2003...................... 499 2004...................... 101 ------ Total $3,082 ====== H. New England Power Pool (NEPOOL) Generation Pricing Disputes with respect to interpretation and implementation of the NEPOOL market rules have arisen with respect to various competitive product markets. In certain cases, Select Energy and the NU operating companies stand to gain as a result of resolution of such disputes. In other cases, Select Energy and the NU operating companies could incur additional costs as the result of resolution of the disputes. The various disputes are in various stages of resolution through alternative dispute resolution and regulatory review. It is too early to tell the level of potential gain or loss that may result upon resolution of these issues. 8. Market Risk and Risk Management Instruments Interest Rate Risk Management: NAEC uses swap instruments with financial institutions to hedge against interest rate risk associated with its $200 million variable-rate bank note. Under the agreements, NAEC exchanges quarterly payments based on a differential between a fixed contractual interest rate and the 3-month LIBOR rate at a given time. As of December 31, 1999 and 1998, NAEC had outstanding agreements with a total notional value of $200 million and mark-to-market positions of positive $0.5 million and negative $2.3 million, respectively. Energy Price Risk Management: Beginning in 1997 through 1999, CL&P used swap instruments with financial institutions to hedge the energy price risk created by long-term negotiated energy contracts. These agreements were intended to minimize exposure associated with rising fuel prices by managing a portion of CL&P's cost of producing power for these negotiated energy contracts. In 1999, CL&P divested substantially all of its fossil and hydroelectric generation assets and agreed to transfer the rights and obligations related to the long-term negotiated energy contracts to an unregulated affiliate. Accordingly, the fuel swap positions were marked-to-market and CL&P recognized a loss of $5.2 million. In January 2000, the fuel swap positions were liquidated. Credit Risk: These agreements have been made with various financial institutions, each of which is rated "A3" or better by Moody's rating group. NAEC is exposed to credit risk on its respective market risk management instruments if the counterparties fail to perform their obligations. Management anticipates that the counterparties will fully satisfy their obligations under the agreements. Unregulated Energy Services Market Risk: NU's unregulated companies, as major providers of electricity and natural gas, have certain market risks inherent in their business activities. Market risk represents the risk of loss that may impact the companies' financial position, results of operations or cash flows due to adverse changes in commodity market prices. In 1999, the companies increased their volume of electricity and gas marketing activities, increasing their risks. Policies and procedures have been established to manage these exposures including the use of risk management instruments. 9. Minority Interest in Consolidated Subsidiary CL&P Capital LP (CL&P LP), a subsidiary of CL&P, previously had issued $100 million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS), Series A. CL&P has the sole ownership interest in CL&P LP, as a general partner, and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance, CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million capital contribution, back to CL&P in the form of an unsecured debenture. CL&P consolidates CL&P LP for financial reporting purposes. Upon consolidation, the unsecured debenture is eliminated, and the MIPS securities are accounted for as a minority interest. 10. Fair Value of Financial Instruments The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and cash equivalents: The carrying amounts approximate fair value due to the short-term nature of cash and cash equivalents. Supplemental Executive Retirement Plan (SERP) Investments: Investments held for the benefit of the SERP are recorded at fair market value. The investments having a cost basis of $5.8 million and $5.4 million held for benefit of the SERP were recorded at their fair market values at December 31, 1999 and 1998 of $9.2 million and $8.7 million, respectively. Nuclear decommissioning trusts: The investments held in the NU system companies' nuclear decommissioning trusts were marked-to-market by $129 million as of December 31, 1999, and $110.4 million as of December 31, 1998, with corresponding offsets to the accumulated provision for depreciation. The amounts adjusted in 1999 and 1998 represent cumulative net unrealized gains. The cumulative gross unrealized holding losses were immaterial for both 1999 and 1998. Preferred stock and long-term debt: The fair value of the NU system's fixed- rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of the NU system's financial instruments and the estimated fair values are as follows: At December 31, 1999 Carrying Fair (Millions of Dollars) Amount Value Preferred stock not subject to mandatory redemption................... $ 136.2 $ 164.0 Preferred stock subject to mandatory redemption...................... 167.5 166.8 Long-term debt - First mortgage bonds...................... 1,193.2 1,209.5 Other long-term debt...................... 1,638.3 1,430.1 MIPS........................................ 100.0 97.3 At December 31, 1998 Carrying Fair (Millions of Dollars) Amount Value Preferred stock not subject to mandatory redemption................... $ 136.2 $ 97.0 Preferred stock subject to mandatory redemption...................... 213.8 205.9 Long-term debt - First mortgage bonds...................... 1,984.0 2,003.6 Other long-term debt...................... 1,654.9 1,682.7 MIPS........................................ 100.0 102.0 11. Other Comprehensive Income The accumulated balance for each other comprehensive income item is as follows: Current December 31, Period December 31, 1998 Change 1999 (Thousands of Dollars) Foreign currency translation adjustments........ $ (1) $ 1 $ - Unrealized gains on securities... 2,019 118 2,137 Minimum pension liability adjustment..................... (613) - (613) ------- ---- ------- Accumulated other comprehensive income........... $1,405 $119 $1,524 ======= ==== ======= Current December 31, Period December 31, 1997 Change 1998 (Thousands of Dollars) Foreign currency translation adjustments........ $ (1) $ - $ (1) Unrealized gains on securities... - 2,019 2,019 Minimum pension liability adjustment..................... - (613) (613) ------- ------- ------- Accumulated other comprehensive income........... $ (1) $1,406 $1,405 ======= ======= ======= The changes in the components of other comprehensive income are reported net of the following income tax effects: 1999 1998 1997 (Thousands of Dollars) Foreign currency translation adjustments........................... $ - $ - $359 Unrealized gains on securities.......... (71) (1,222) - Minimum pension liability adjustment............................ - 398 - ----- -------- ---- Other comprehensive income.............. $(71) $ (824) $359 ===== ======== ==== 12. Earnings Per Share Earnings per share (EPS) is computed based upon the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock. The following table sets forth the components of basic and diluted EPS: (Millions of Dollars, except share information) 1999 1998 1997 Income/(loss) after interest charges................ $57.0 $(120.4) $ (99.7) Preferred dividends of subsidiaries................. 22.8 26.4 30.3 ----------- ------------ ------------ Net income/(loss)................. $34.2 $(146.8) $(130.0) =========== ============ ============ Basic EPS common shares outstanding (average)..... 131,415,126 130,549,760 129,567,708 Dilutive effect of employee stock options.......... 616,447 - (a) - (a) ----------- ------------ ------------ Diluted EPS common shares outstanding (average)........... 132,031,573 130,549,760 129,567,708 =========== ============ ============ Basic earnings/(loss) per share... $0.26 $(1.12) $(1.01) Diluted earnings/(loss) per share. $0.26 $(1.12) $(1.01) (a) The addition of dilutive potential common shares would be anti-dilutive for 1998 and 1997 and was not included. 13. Mode 1 In August 1998, NorthEast Optic Network, Inc. (NEON) issued 4,000,000 new common shares on the open market in an initial public offering (IPO). The IPO had the effect of decreasing Mode 1's ownership interest in NEON from 40.78 percent to 30.74 percent. The shares were issued at an amount greater than Mode 1's investment, resulting in a $13.7 million pretax increase to Mode 1's equity. NU's accounting policy is to recognize the gain or loss from this type of change in ownership interest in net income. However, as a result of the startup nature of NEON's operations, this change in ownership interest was recognized in additional paid in capital. In conjunction with the IPO, Mode 1 sold 217,997 NEON shares, resulting in a pretax gain of $1.7 million and further reducing its ownership interest to 29.4 percent of the outstanding common shares of NEON. On November 23, 1999, NEON entered into two agreements with unaffiliated companies. Under the agreements, NEON will provide network transport and carrier services among the service areas of NEON and the two unaffiliated companies and each company will provide connectivity from the backbone system to their respective local loops. Additionally, each company will manage their local distribution into their respective end-users' locations. NEON will also develop, operate and market the combined telecommunications infrastructure created under the two agreements. As the agreements are implemented, the two unaffiliated companies will ultimately obtain 10.75 percent and 9.25 percent ownership interests, respectively, in NEON and will each nominate one member to the NEON Board of Directors. The agreements are subject to regulatory approvals, which are expected by the spring of 2000. 14. Segment Information Effective January 1, 1999, the NU system companies adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." The NU system is organized between regulated utilities and unregulated energy services. The regulated utilities segment represents 87 percent of the NU system's total revenue and is comprised of several business units including generation, transmission and distribution. The unregulated energy services segment in the following table includes NGC, NGS, Select Energy and HEC. Other in the following table includes the results for Mode 1. Mode 1 had a net loss of $4.3 million for the year ended December 31, 1999. Interest expense included in Other primarily relates to the debt of NU parent. Inter-segment eliminations of revenues and expenses are also included in Other. Regulated utilities revenues primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer. The unregulated energy services segment has a major customer whose purchases represented 46 percent of its total revenues for the year ended December 31, 1999. For the Year Ended December 31, 1999 Unregulated Regulated Energy (Millions of Dollars) Utilities Services Other Total Operating revenues $3,888.7 $606.3 $(23.7) $4,471.3 Operating expenses (3,495.9) (646.7) 15.9 (4,126.7) --------- ------- ------- --------- Operating income/(loss) 392.8 (40.4) (7.8) 344.6 Other (loss)/income (36.4) (1.2) 13.7 (23.9) Interest expense (247.8) (1.0) (14.9) (263.7) Preferred dividends (22.8) - - (22.8) --------- ------- ------- --------- Net income/(loss) $ 85.8 $(42.6) $ (9.0) $ 34.2 ========= ======= ======= ========= Total assets $9,388.3 $222.5 $ 77.3 $9,688.1 ========= ======= ======= ========= Prior to 1999, the NU system evaluated management performance using a cost- based budget, therefore business segment reporting on a comparative basis will not be available until the year 2000. 15. Merger Agreement with Con Edison On October 13, 1999, NU and Con Edison announced that they have agreed to a merger to combine the two companies. The shareholders of NU will receive $25 per share in a combination of cash and Con Edison common stock. NU shareholders also have the right to receive an additional $1 per share if a definitive agreement to sell its interests (other than that now held by PSNH) in Millstone 2 and 3 is entered into and recommended by the Utility Operations and Management Unit of the DPUC on or prior to the later of December 31, 2000, or the closing of the merger. Further, the value of the amount of cash or common stock to be received by NU shareholders is subject to increase by an amount of $0.0034 per share per day for each day that the transaction does not close after August 5, 2000. Upon completion of the merger, NU will become a wholly owned subsidiary of Con Edison. The purchase is subject to the approval of the shareholders of both companies and several regulatory agencies. The companies anticipate that these regulatory procedures will be completed by July 2000. EX-99.2 5 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS Exhibit 99.2 to Form 8-K Report Report of Independent Public Accountants To the Board of Trustees and Shareholders of Northeast Utilities: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northeast Utilities (a Massachusetts trust) and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of income, comprehensive income, shareholders' equity, cash flows and income taxes for each of the three years in the period ended December 31, 1999. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles. /s/ ARTHUR ANDERSEN LLP Hartford, Connecticut January 25, 2000 EX-99.3 6 MANAGEMENT DISCUSSION AND ANALYSIS Exhibit 99.3 to Form 8-K Report Financial Condition Overview The financial improvement that began in 1998 continued throughout 1999 at Northeast Utilities (NU or the company), despite rate reductions in Connecticut and Massachusetts, and larger operating losses at NU's unregulated subsidiaries. NU's results benefited from the successful restart of the Millstone 2 nuclear unit, the strong operating performance delivered by the Millstone 3 and Seabrook Station (Seabrook) nuclear units, retail sales growth, and continued control over operation and maintenance (O&M) expenses. The financial improvement allowed NU to resume the payment of a quarterly dividend for the first time since early 1997. NU shareholders received a common dividend of 10 cents per share in the fourth quarter of 1999. During 1999, NU resolved key industry restructuring issues by establishing initial stranded cost recovery levels and standard offer service tariffs and agreements in Connecticut and by receiving final approval of a restructuring plan in Massachusetts. The auction of substantially all of the fossil and hydroelectric generation assets owned by The Connecticut Light and Power Company (CL&P) and Western Massachusetts Electric Company (WMECO) and the auction of their respective interests in the output of the Millstone units, moved both companies along in their transition into purely electric transmission and distribution companies, as contemplated by restructuring legislation in both Connecticut and Massachusetts. Also in 1999, the company made significant progress toward resolving restructuring issues in the state of New Hampshire by negotiating a global restructuring settlement that is still subject to regulatory approval. NU earned $34.2 million, or $0.26 per share in 1999, compared with a loss of $146.8 million, or $1.12 per share in 1998 and a loss of $130 million, or $1.01 per share in 1997. Absent significant one-time items, the NU system earned $0.89 per share in 1999, compared with a loss of $0.30 per share in 1998 and a loss of $0.76 per share in 1997. NU's improved 1999 operating results are attributed to better operating performance of its nuclear units, a strong economy and continued strong expense control throughout the year. The 1999 results included $83 million, or $0.63 per share, in after-tax write-offs. These write-offs were associated with the settlement of nuclear related issues ($0.39 per share), industry restructuring ($0.15 per share) and fees related to the pending merger with Consolidated Edison, Inc. (Con Edison) ($0.09 per share). During 1998, NU recorded $133 million, or $0.82 per share, in after-tax write-offs associated with a rate decision in Connecticut, the retirement of Millstone 1 and nonrecurring charges at Charter Oak Energy, an unregulated generation subsidiary of NU. The "Agreement to Settle PSNH Restructuring" (Settlement Agreement), involving the Public Service Company of New Hampshire (PSNH) calls for an after-tax write-off of $225 million. However, that write-off was not recorded in 1999, as key aspects of the Settlement Agreement still required regulatory and legislative approval and it was not possible to determine the ultimate resolution of this matter at year end. In 1999, NU's revenues exceeded $4 billion for the first time, totaling $4.47 billion, up 18.7 percent from revenues of $3.77 billion in 1998. The growth was primarily due to increased electric sales by Select Energy, Inc. (Select Energy), NU's unregulated power marketing subsidiary, and higher retail sales from NU's regulated subsidiaries. Select Energy's revenues totaled $554.9 million in 1999, compared with $29.3 million in 1998. Revenues from the company's regulated subsidiaries also benefited from a 3.8 percent increase in retail sales, the largest increase in retail sales in recent history. Approximately 40 percent of that growth was due to weather related factors that included a hotter than normal summer. The balance of that increase was due to economic expansion in NU's service territories. Aside from increased revenues, the primary reason for better operating performance in 1999 was the return to service from extended outages of Millstone 3 in July 1998 and Millstone 2 in May 1999. The return to service of those units reduced replacement power costs by $215 million in 1999, compared to 1998. Retail rate reductions involving CL&P and WMECO offset some of the growth in revenues. CL&P's rates were reduced 5 percent in early 1999. CL&P's rates were further reduced in January 2000 by 5 percent. The additional 5 percent rate reduction will offset some of the growth in future revenues. WMECO's rates were reduced a total of 15 percent from its August 1997 rates, 11.8 percent adjusted for inflation, between March 1998 and September 1999. Sharply higher purchased-power costs at Select Energy also offset many of the benefits from higher sales. Select Energy recorded a net loss of $38.8 million in 1999, compared with a net loss of $13.4 million in 1998. Also in 1999, Select Energy's earnings were reduced by $4.1 million related to retail contracts which extend through 2003. NU's ability to continue improving financial performance in 2000 will depend largely on continued regulated sales growth and on successful control of O&M expenses. Additionally, NU plans to meet the challenges of assimilating Yankee Energy System, Inc. (Yankee) into its business and achieving, by July 2000, the shareholder and regulatory approvals needed to complete the merger with Con Edison. NU also hopes to complete in 2000 the majority of restructuring work remaining, primarily the implementation of the Settlement Agreement in New Hampshire, the issuance of rate reduction bonds (securitization) to lower stranded costs at CL&P, WMECO and PSNH, and the auction of NU's ownership interests in the Millstone units. Additionally, during 2000, NU intends to continue focusing on the growth of its competitive businesses. NU's ability to reverse losses in its unregulated businesses will depend largely on the energy marketing subsidiary's ability to better balance its supply options, including soon to be acquired hydroelectric generation assets, with sales commitments. Mergers In 1998 and 1999, NU management concluded that the pace of deregulation was accelerating throughout the northeastern United States and that shareholders would benefit from NU, not only remaining a major provider of electric transmission and distribution service, but also becoming an unregulated marketer of both electricity and natural gas. NU management also concluded that as a result of the changes occurring in the highly competitive electric utility industry, increased size would be crucial to achieve its objective of being a leading provider of energy products and services in the Northeast. NU management discussed potential business combinations with several electric utilities in the northeastern United States. On October 13, 1999, NU announced an agreement to merge with Con Edison, a financially stronger utility based in New York. Con Edison will pay approximately $3.8 billion for all of the outstanding common stock of NU and will assume NU's debt, capitalized leases and preferred securities which totaled $3.7 billion at December 31, 1999. Under the merger agreement, NU shareholders will receive $25 per share, in a combination of cash and Con Edison common stock. NU shareholders will have the right to elect cash or stock subject to proration if the total elections exceed 50 percent in either cash or stock. NU shareholders who elect to receive stock will receive the number of shares of Con Edison stock based on the average trading prices, determined pursuant to a formula, during a fixed period prior to the closing. So long as such average trading prices are between $36 and $46 per share, the total value of the Con Edison common stock received by NU shareholders will be $25 per share. NU shareholders also have the right to receive an additional $1 per share in value as long as definitive agreements to sell its interests (other than that now held by PSNH) in Millstone 2 and 3 are entered into and recommended by the Utility Operations and Management Unit of the Connecticut Department of Public Utility Control (DPUC) on or prior to the later of December 31, 2000, or the closing of the merger. In addition, another $0.0034 per share per day for every day beyond August 5, 2000, that the merger is not consummated is added to the purchase price. If Con Edison's stock price is below $36 per share, then the value received for the stock portion will be less than $25 per share. The merger will create the nation's largest electric distribution system with more than 5 million customers and one of the 15 largest natural gas distribution systems with 1.4 million customers. NU and Con Edison filed with various state and federal regulatory bodies in January 2000 to secure approval of the merger. The two companies expect these regulatory proceedings can be completed by the end of July 2000. Also in 1999, NU management concluded that the Northeast Utilities system (NU system) would be stronger and customers could be better served if NU reentered the natural gas distribution business that it had exited in 1989 and examined several potential businesses in New England. By adding gas to NU's energy mix, NU will be able to broaden its services to its existing customers and will have additional opportunities for long-term growth. In June 1999, NU announced an agreement to merge with Yankee. Yankee is the natural gas division that CL&P divested in 1989. Yankee shareholders will receive $45 per share, or approximately $479.6 million in cash and NU common stock. In addition, NU will assume Yankee's outstanding debt of approximately $240.8 million. Yankee shareholders will receive 45 percent of the $479.6 million in NU common stock and 55 percent in cash. NU will finance the cash portion of the transaction and will meet the stock component of the transaction by issuing new shares. NU expects to redeem a similar amount of shares later this year by closing out forward share purchase transactions with proceeds from restructuring. The forward share purchase transactions were arranged in late 1999 with two financial institutions. NU is prohibited from purchasing additional shares under its merger agreement with Con Edison. The merger will return to NU Connecticut's largest natural gas distribution system, as well as several unregulated businesses involved in energy services, collections and other areas. The Yankee merger received final DPUC approval in December 1999 and Securities and Exchange Commission (SEC) approval in January 2000. The merger is expected to close in early March 2000. Liquidity During 1999, strong sales growth, improved nuclear performance and continued control of O&M expenses resulted in net cash flows provided by operations of $614.2 million in 1999, compared to $663.3 million in 1998 and $340.6 million in 1997. On December 15, 1999, CL&P closed on the sale of 2,235 megawatts (MW) of fossil generation assets with an unaffiliated company. Proceeds from the sale totaled $516.9 million, including payments for fuel and inventory. CL&P used the proceeds primarily to par call $406 million of first mortgage bonds in December 1999. CL&P also used $57.5 million to buy out its lease of four 40 MW turbines. On July 26, 1999, WMECO closed on the sale of 290 MW of fossil and hydroelectric generation assets with an affiliate of Con Edison. Proceeds from the sale were $48.5 million. Proceeds from these generation asset sales are included in net cash flows provided by investing activities. Including construction expenditures and investments in nuclear decommissioning trusts, net cash flows provided by investing activities were $151.2 million in 1999, compared with net cash flows used in investing activities of $295.2 million in 1998 and $293 million in 1997. The strong operating cash flows provided by NU's regulated businesses and the proceeds from generation asset sales enabled the NU system to substantially reduce its outstanding debt. As of December 31, 1999, the NU system's total debt level, including capital lease obligations, was $3.3 billion, compared with $3.9 billion as of December 31, 1998, and $4.1 billion as of December 31, 1997. The net cash flows used in financing activities were $646.4 million in 1999, compared to $375.3 million in 1998 and $98.5 million in 1997. This included $864 million paid in 1999 to retire long-term debt and preferred stock, compared to $331.8 million in 1998 and $313.8 million in 1997. Cash dividends on common shares paid in 1999 were $13.2 million, compared to no cash dividends in 1998 and $32.1 million in 1997. Payments made for preferred stock dividends were $22.8 million, $26.4 million and $30.3 million for 1999, 1998 and 1997, respectively. The NU system's access to capital also benefited from the strong operating performance at Millstone 2 and 3, continued progress toward the resolution of all restructuring issues in New Hampshire and the announced merger with Con Edison. During 1999, NU system securities received several upgrades from three credit rating agencies. CL&P's and WMECO's senior secured bonds achieved investment grade ratings for the first time since early 1997 and PSNH's bonds were upgraded to investment grade by Standard & Poor's (S&P) for the first time since early 1994. At year end, all securities were under review for possible upgrades, or on "credit watch" with positive implications by S&P, Moody's Investors Service and Fitch IBCA. The rating agency upgrades benefited NU's efforts to broaden its credit lines. On November 19, 1999, NU parent entered into a $350 million, 364-day unsecured revolving credit facility which allows NU parent access to $350 million in a combination of cash and letters of credit. NU parent provides credit assurance in the form of guarantees of letters of credit, performance guarantees and other assurances for the financial performance obligations of certain of its unregulated subsidiaries, particularly Select Energy. Over the course of 1999, NU parent sought and received approval from the SEC to increase the limit of such credit assurance arrangements from $75 million to $500 million. However, NU is limited under certain loan agreements to $350 million of such arrangements without creditor approval. As of December 31, 1999, NU had provided approximately $190 million of such credit assurances. Also on November 19, 1999, CL&P and WMECO entered into a new 364-day revolving credit facility for $500 million, replacing the previous $313.75 million facility which was to expire on November 21, 1999. The revolving credit facility, which is secured by second mortgaes on Millstone 2 and 3, will be used to bridge gaps in working capital and provide short-term liquidity. CL&P may draw up to $300 million and WMECO may draw up to $200 million under the facility. Once CL&P and WMECO receive the proceeds from securitization, the $500 million facility will be reduced to $300 million, with a $200 million limit for CL&P and a $100 million limit for WMECO. As of December 31, 1999, CL&P had $90 million and WMECO had $123 million outstanding under this facility. For further information regarding the NU parent revolving credit facility and the CL&P and WMECO revolving credit facility, see Note 3, "Short-Term Debt," to the consolidated financial statements. PSNH's $75 million revolving credit agreement was terminated on April 14, 1999. PSNH currently funds its operations through cash on hand and operating cash flows. As of December 31, 1999, PSNH had $182.6 million of cash and cash equivalents. On April 14, 1999, PSNH renewed bank letters of credit that support nearly $110 million of taxable variable-rate pollution control bonds. CL&P also has arranged financing through the sale of its accounts receivable. CL&P can finance up to $200 million through this facility. As of December 31, 1999, CL&P had $170 million outstanding under this facility. WMECO terminated its $40 million accounts receivable credit facility on June 30, 1999. In late 1999, NU arranged forward purchase transactions for approximately 10 million NU common shares with two financial institutions (counterparties). To effect these transactions, the counterparties purchased, on the open market between November 1999 and January 2000, NU common shares, at an average price per share of $21.26, in a total aggregate amount of $215 million. The counterparties maintain ownership of the shares until the transactions are settled. Additionally, NU will continue to accrue fees on the total aggregate amount at LIBOR plus 2.5 percent per annum, until the transactions are settled. These transactions can be settled in cash or NU common shares at the company's discretion. As required under the terms of the contracts, NU must settled the transactions no later than December 31, 2000 for an aggregate purchase price equal to $215 million. However, NU expects to settle these purchase transactions with the proceeds from restructuring in the second half of 2000. If prior to the settlement date, NU's share price falls below $15.80 per share, NU may be required to provide the counterparties with additional collateral. During 2000, the NU system companies hope to receive regulatory approval to begin the process of securitizing approximately $2.5 billion of approved stranded costs. Securitization involves issuing rate reduction bonds with interest rates lower than the company's weighted average cost of capital. Proceeds from securitization will be used to significantly reduce the capitalization of NU's regulated subsidiaries and buyout or buydown certain purchased-power contracts with a number of nonutility generators. Restructuring During 1999, Connecticut and Massachusetts made significant progress in resolving industry restructuring issues. Restructuring orders issued in Connecticut and Massachusetts allowed NU to determine the impacts of discontinuing Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," for the generation portion of CL&P's and WMECO's businesses. In both states, the transmission and distribution portion of those businesses will continue to be cost-of-service regulated. In addition, the restructuring orders provided for a transition charge which allows for the recovery of CL&P's and WMECO's generation-related regulatory assets and prudently incurred stranded costs. The process of restructuring the electric utility industry in New Hampshire has not yet been concluded, however, significant progress has been made over the past year. In August 1999, PSNH and state officials reached a Settlement Agreement, addressing all rate and restructuring issues involving PSNH, which is awaiting New Hampshire Public Utilities Commission (NHPUC) approval. Connecticut During April 1999, CL&P filed its standard offer service plan with the DPUC and received a decision on October 1, 1999, as amended on December 15, 1999. In that decision, the DPUC approved the recovery of CL&P's regulatory assets and certain stranded costs associated with CL&P's nuclear generation assets and established the methodology for setting CL&P's standard offer rates, including the transition charge and transmission and distribution rates. The DPUC ruled on CL&P's stranded cost filing in July 1999 approving $3.5 billion of stranded cost recovery, which is utilized, in part, in the determination of the transition charge. As provided for in the electric utility restructuring legislation enacted in April 1998, 35 percent of CL&P's customers were able to choose their electric generation supplier on January 1, 2000, with the remaining 65 percent having choice on July 1, 2000. The major components of rates are a transmission and distribution charge, a generation charge and a transition charge. For those customers who do not or are unable to choose another competitive electric generation supplier, CL&P will supply standard offer or generation service at an average rate of $0.04813 per kilowatt-hour (kWh) through December 31, 2003. The revenues attributable to standard offer (generation) service are expected to exceed the actual cost of providing generation and the difference will be applied against stranded costs. In accordance with a plan approved by the DPUC, one-half of the CL&P standard offer load was procured through a competitive bidding process, with the remaining one-half of the power being supplied by an affiliated company. The contracts are in place through the end of 2003. For further information regarding commitments and contingencies related to the Connecticut restructuring order, see Note 7A, "Commitments and Contingencies - Restructuring - Connecticut," to the consolidated financial statements. Massachusetts Massachusetts enacted electric utility restructuring legislation in November 1997. Based on an interim order approving WMECO's restructuring plan filed in December 1997, WMECO's customers were able to choose an alternative retail electricity supplier beginning on March 1, 1998. In 1999, the Massachusetts Department of Telecommunications and Energy (DTE) issued its final decision on WMECO's restructuring plan. In that decision, the DTE permitted WMECO to recover its generation-related regulatory asset balances and its nuclear decommissioning costs. However, the DTE disallowed any return on Millstone 2 and 3 starting March 1, 1998, until they returned to service and on Millstone 1 for its remaining life. The pretax impact of these disallowances was $41 million. The DTE also approved one-year contracts with the winning bidders of the standard offer and default service supply auction. For further information regarding commitments and contingencies related to the Massachusetts restructuring order, see Note 7A, "Commitments and Contingencies - - Restructuring - Massachusetts," to the consolidated financial statements. Generation Asset Divestitures - Connecticut and Massachusetts The Connecticut and Massachusetts restructuring laws required CL&P and WMECO to divest of their nonnuclear generation assets and utilize substantially all of the net gains from any sales to offset stranded costs. During 1999, WMECO and CL&P sold their nonnuclear generation assets resulting in net gains of $22.4 million and $286.5 million, respectively. A corresponding amount of regulatory assets was amortized. In September 1999, NU announced that the Millstone nuclear generation assets of its subsidiaries, CL&P and WMECO, will be put up for auction as soon as practical. For further information regarding commitments and contingencies related to the Connecticut and Massachusetts generation asset divestitures, see Note 7A, "Commitments and Contingencies - Restructuring - Nuclear Generation Assets Auction," to the consolidated financial statements. New Hampshire In August 1999, NU, PSNH and the state of New Hampshire signed the Settlement Agreement which will resolve a number of pending regulatory and court proceedings related to PSNH. The Settlement Agreement is awaiting approval of the NHPUC and is subject to legislative approval of securitization. The key components of the agreement include an after-tax write-off of $225 million of stranded costs; the recovery of the remaining stranded costs; the securitization of $725 million of approved stranded costs; the sale of generation assets and wholesale power entitlements, with transition service being available to customers for three years; a reduction in rates of an average of 18.3 percent, and the opening of the New Hampshire electricity market to competition. For further information regarding commitments and contingencies related to the New Hampshire Settlement Agreement, see Note 7A, "Commitments and Contingencies - Restructuring - New Hampshire," to the consolidated financial statements. Unregulated Energy Services The energy marketing and brokering business is intensely competitive, with many companies with larger financial resources than NU's bidding for business in the deregulating New England market. The sharply fluctuating cost of power supply caused by, among other things, weather extremes, plant outages and fuel costs, and a lack of load-following generating facilities, have made it difficult for Select Energy to economically match its wholesale power purchases with its power supply obligations. In 1999, Select Energy recorded a net loss of $38.8 million on revenues of $554.9 million, compared to a net loss of $13.4 million on revenues of $29.3 million in 1998. Select Energy's ability to economically compete has also been affected by NU's weakened financial position caused by the extended Millstone outages which ended in mid 1999. In 2000, Select Energy's expected contract with an affiliated company, Northeast Generation Company, to purchase 1,329 MW of capacity and energy should significantly reduce the load-following risk and allow Select Energy to better manage its portfolio profitability. Select Energy's goal is to be the regional and national leader in providing standard offer service to those Northeast markets opened to retail competition. Currently, Select Energy provides more than 5,000 MW of standard offer load, making it the largest provider of standard offer service in the Northeast. On December 22, 1999, Select Energy and an unaffiliated company signed a 6-month power supply agreement, effective January 1, 2000, to meet the utility's standard offer service requirements, which are expected to exceed 3,000 MW. This contract does not include renewal or termination provisions, and payment is due within ten days of the receipt of the bill. Select Energy has been serving this standard offer load since December 1998. During 1999, revenues billed to this customer totaled $276.1 million, or approximately 46 percent of Select Energy's revenues. On January 1, 2000, Select Energy began serving CL&P with one-half of its approximately 2,000 MW standard offer requirement for a 4-year period. The CL&P standard offer contract does not include renewal provisions. Select Energy can terminate the contract if the Federal Energy Regulatory Commission (FERC) or DPUC require changes to the contract which create material adverse economic impact to Select Energy which cannot be cured. These power supply contracts are expected to provide Select Energy with over 50 percent of its revenues in the year 2000. In addition, beginning in January 2000, Select Energy assumed responsibility for serving approximately 30 market-based wholesale contracts, totaling approximately 500 MW, throughout New England with electric energy supply that was previously provided by CL&P and WMECO. For the most part, the prices are fixed by contract and applicable to actual volumes. Nuclear Generation Millstone Nuclear Units Millstone 3 received the appropriate Nuclear Regulatory Commission (NRC) approvals and resumed operation in July 1998. Millstone 2 received similar NRC approvals, resumed operation and was returned to CL&P's rate base in May 1999. Millstone 3 and 2 achieved annual capacity factors of 81.7 percent and 57.9 percent in 1999, respectively. After a 60-day refueling and maintenance outage, Millstone 3 returned to service on June 29, 1999, and has achieved a 98.1 percent capacity factor through December 31, 1999. Since returning to service in May 1999, Millstone 2 has achieved a 90.3 percent capacity factor through December 31, 1999. NU's total share of O&M expenses associated with Millstone 3 and 2 totaled $261.8 million in 1999, as compared to $323.2 million in 1998 and $406 million in 1997. Millstone 1 is currently in decommissioning status. An auction of the NU system's ownership interests in the Millstone units is expected in 2000 with a closing in 2001. Based on regulatory decisions received in 1999, management expects to recover all of its remaining nuclear stranded costs from retail customers. Seabrook Seabrook achieved an annual capacity factor of 86.4 percent in 1999. However, since returning to service on May 13, 1999, after a 48-day refueling and maintenance outage, Seabrook has achieved a 99 percent capacity factor through December 31, 1999. CL&P anticipates auctioning its 4.06 percent share of Seabrook, with the 35.98 percent share owned by its affiliate North Atlantic Energy Corporation (NAEC) after approval of the Settlement Agreement. The Settlement Agreement with the state of New Hampshire requires divestiture prior to December 31, 2003. Yankee Companies On June 1, 1999, the FERC accepted the offer of settlement which was filed on January 15, 1999, by the Maine Yankee Atomic Power Company (MYAPC). The significant aspects of the settlement allowed MYAPC to collect $33.6 million annually to pay for decommissioning and spent fuel, approved its return on equity of 6.5 percent, permitted full recovery of MYAPC's unamortized investment, including fuel, and set an incentive budget for decommissioning at $436.3 million. On October 15, 1999, the Vermont Yankee Nuclear Power Corporation (VYNPC) agreed to sell its unit for $22 million to an unaffiliated company. Among other commitments, the acquiring company agreed to assume the decommissioning cost of the unit after it is taken out of service, and the VYNPC owners have agreed to fund the uncollected decommissioning cost to a negotiated amount at the time of the closing of the sale. VYNPC's owners have also agreed either to enter into a new purchased-power agreement with the acquiring company or to buy out such future power payment obligations by making a fixed payment to them. CL&P, WMECO and PSNH have elected the buyout option. The VYNPC owners' obligations to close and pay such amounts are conditioned upon their receipt of satisfactory regulatory approval of the transaction, including provision for adequate recovery of these payments. Nuclear Decommissioning The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry regarding the recognition, measurement and classification of decommissioning costs for nuclear units in their financial statements. Currently, the Financial Accounting Standards Board plans to review the accounting for obligations associated with the retirement of long-lived assets, including the decommissioning of nuclear units. If current accounting practices for nuclear decommissioning change, the annual provision for decommissioning could increase relative to 1999, and the estimated cost for decommissioning could be recorded as a liability with recognition of an increase in the cost of the related nuclear unit. However, management does not believe that such a change will have a material impact on the NU system's financial statements due to its current and future ability to recover decommissioning costs through rates. Spent Nuclear Fuel Disposal Costs The United States Department of Energy (DOE) originally was scheduled to begin accepting delivery of spent fuel in 1998. However, delays in confirming the suitability of a permanent storage site continually have postponed plans for the DOE's long-term storage and disposal site. Extended delays or a default by the DOE could lead to consideration of costly alternatives. NU has the primary responsibility for the interim storage of its spent nuclear fuel. Adequate storage capacity exists to accommodate all spent nuclear fuel at Millstone 1. The facilities for Millstone 2 are expected to provide adequate storage to accommodate a full-core discharge from the reactor until 2005 with the implementation of currently planned modifications. Fuel consolidation, which has been licensed for Millstone 2, could provide adequate storage capacity for its projected life. The facilities for Millstone 3 are expected to provide adequate storage for its projected life with the addition of new storage racks. Seabrook is expected to have spent fuel storage capacity until at least 2010. Meeting spent fuel storage requirements beyond these periods could require new and separate storage facilities. For further information regarding spent nuclear fuel disposal costs, see Note 7D, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements. Market Risk and Risk Management Instruments The NU system uses swaps and collars to manage the market risk exposures associated with changes in variable interest rates and energy prices. The NU system uses these instruments to reduce risk by essentially creating offsetting market exposures. Based on the derivative instruments which are currently being utilized by the NU system companies to hedge some of their interest rate and energy price risks, there may be an impact on earnings upon adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," which management has not estimated at this time. Interest Rate Risk Management Instruments Several NU subsidiaries hold variable-rate, long-term debt, exposing the NU system to interest rate risk. In order to hedge some of this risk, interest rate risk management instruments have been entered into on NAEC's $200 million variable-rate note. A 10 percent increase in market interest rates above the 1999 weighted average variable rate during 2000 would result in an immaterial impact on interest expense. Energy Price Risk Management Instruments In the generation of electricity, the most significant segment of the variable cost component is the cost of fuel. Typically, most of CL&P's fuel purchases were protected by a regulatory fuel price adjustment clause. However, for a specific, well-defined volume of fuel that was excluded from the energy price adjustment clause, CL&P employed energy price risk management instruments to protect itself against the risk of rising fuel prices, thereby limiting fuel costs and protecting its profit margins. These risks were created by the sale of long-term fixed-price electricity sales contracts to wholesale customers. In 1999, CL&P divested substantially all of its fossil and hydroelectric generation assets and also transferred the rights and obligations of its long-term fixed-price contracts to an unregulated affiliate. As a result, the fuel swap positions were marked-to-market and CL&P recognized a loss of $5.2 million. In January 2000, the fuel swap positions were liquidated. Unregulated Energy Services Market Risk NU's unregulated companies, as major providers of electricity and natural gas, have certain market risks inherent in their business activities. Market risk represents the risk of loss that may impact the companies' financial position, results of operations or cash flows due to adverse changes in commodity market prices. In 1999, the companies increased their volume of electricity and gas marketing activities, increasing their risks. Policies and procedures have been established to manage these exposures including the use of risk management instruments. Other Matters Environmental Matters NU is subject to environmental laws and regulations structured to mitigate or remove the effect of past operations and to improve or maintain the quality of the environment. For further information regarding environmental matters, see Note 7C, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements. Other Commitments and Contingencies NU is subject to other commitments and contingencies primarily relating to nuclear litigation, nuclear insurance contingencies, its constuction program, long-term contractual arrangements, and the New England Power Pool generation pricing. For further information regarding these other commitments and contingencies, see Note 7, "Commitments and Contingencies," to the consolidated financial statements. Year 2000 Issues The transition into the year 2000 was a success for the NU system. Its mission to provide safe, reliable energy to its customers and to ensure continued operability of critical business functions was not affected by any year 2000 related issues. The projected total cost of the year 2000 program is estimated at $21 million. The total cost to date was funded through operating cash flows. The NU system has incurred and expensed $20 million related to year 2000 readiness efforts. Forward Looking Statements This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts. 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 historical weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, and other presently unknown or unforeseen factors. Results Of Operations The components of significant income statement variances for the past two years are provided in the table below. Income Statement Variances (Millions of Dollars) 1999 over/(under) 1998 1998 over/(under) 1997 Amount Percent Amount Percent Operating Revenues $704 19% $(67) (2)% Operating Expenses: Fuel, purchased and net interchange power 428 29 (8) (1) Other operation 52 7 (116) (13) Maintenance (58) (15) (103) (20) Depreciation (31) (9) (22) (6) Amortization of regulatory assets, net 393 (a) 79 64 Federal and state income taxes 93 (a) 4 (a) Taxes other than income taxes 9 4 (2) (1) Gain on sale of utility plant (309) - - - Total operating expenses 584 16 (101) (3) Operating income 120 53 34 18 Equity in earnings of regional nuclear generating and transmission companies (7) (59) (1) (9) Nuclear unrecoverable costs 72 50 (143) (100) Other income/(loss), net (19) (a) 19 61 Interest charges, net (5) (2) (3) (1) Preferred dividends of subsidiaries (4) (14) (4) (13) Net income/(loss) 181 (a) (17) (13) (a) Percentage greater than 100. Operating Revenues Total revenues increased by $704 million or 19 percent in 1999 due to higher revenues from the competitive companies ($552 million), higher regulated wholesale revenues ($107 million) and higher regulated retail revenues ($45 million). The competitive companies' increase is due to higher revenues from Select Energy ($526 million) and HEC Inc. (HEC) ($26 million). Select Energy's revenues were higher in 1999 as a result of new contracts for energy sales. The regulated wholesale revenue increase is primarily due to higher energy sales and related capacity and transmission revenues. The regulated retail increase is primarily due to higher retail sales ($99 million) and the impact of Millstone 2 and 3 being returned to CL&P's rate base ($13 million). These retail increases were partially offset by retail rate reductions for CL&P and WMECO ($55 and $12 million, respectively). Regulated retail kilowatt-hour sales increased by 3.8 percent. Retail revenues decreased by $199 million in 1998 due to retail rate reductions for CL&P, PSNH and WMECO and the accounting impact of Millstone 2 and 3 being removed from CL&P's rate base. Wholesale revenues decreased by $32 million primarily as a result of the terminated contract with the Connecticut Municipal Electric Cooperative (CMEEC). Other revenues decreased $50 million due to lower billings to outside companies for reimbursable costs and price differences among customer classes. These decreases were partially offset by higher fuel recoveries and higher retail sales volumes. Fuel recoveries increased by $166 million primarily due to higher fuel revenues from PSNH as a result of a higher fuel and purchased-power adjustment clause rate. Retail kilowatt-hour sales were 1.9 percent higher and contributed $48 million to nonfuel revenues in 1998 primarily as a result of economic growth in all three states. Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense increased in 1999, primarily due to higher purchased energy and capacity costs as a result of higher sales for Select Energy ($521 million), regulated wholesale ($86 million) and regulated retail ($36 million), partially offset by lower replacement power costs due to the return to service of Millstone 2 and 3 ($215 million). The change in fuel, purchased and net interchange power expense in 1998 was not significant. Other Operation and Maintenance Other O&M expenses decreased in 1999, primarily due to lower costs at the Millstone units ($125 million), partially offset by the recognition of environmental insurance proceeds in 1998 and additional environmental reserves in 1999 ($30 million), higher transmission and power exchange expenses ($35 million), higher spending at Seabrook ($10 million) as a result of the refueling outage, higher expenditures for HEC and the competitive businesses ($32 million), and expenses associated with the Con Edison merger ($12 million) in 1999. Other O&M expenses decreased in 1998, primarily due to lower costs at the Millstone units ($159 million), lower costs at the Seabrook and Yankee companies' nuclear units ($50 million), the recognition of environmental insurance proceeds ($27 million), and lower administrative and general expenses ($26 million). These decreases were offset partially by higher recognition of nuclear refueling outage costs primarily as a result of the 1996 CL&P rate settlement ($29 million). Depreciation Depreciation decreased in 1999 and 1998, primarily due to the retirement of Millstone 1. Amortization of Regulatory Assets, Net Amortization of regulatory assets, net increased in 1999, primarily due to the increased amortization associated with the gain on the sale of CL&P's and WMECO's fossil and hydroelectric generation assets ($309 million), the amortization of CL&P's and WMECO's Millstone 1 remaining investment ($56 million) and the reclassification of the depreciation on the nuclear plants to regulatory assets ($23 million). Amortization of regulatory assets, net increased in 1998, primarily due to accelerated amortizations in accordance with regulatory decisions for CL&P ($49 million), the amortization of NAEC's Seabrook deferred return ($79 million) and the beginning of the amortization of CL&P's Millstone 1 investment ($23 million). These increases were partially offset by the lower amortization of the PSNH acquisition premium ($40 million). Federal and State Income Taxes The consolidated statement of income taxes provides a reconciliation of actual and expected tax expense. The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions. In past years, this rate-making treatment has required the company to provide the customers with a portion of the tax benefits associated with accelerated tax depreciation in the year it is generated (flow-through depreciation). As these flow-through differences turn around, higher tax expense is recorded. Federal and state income tax expense increased approximately $93 million in 1999, primarily due to the significant increase in pretax earnings. Significant variances of other items include a $10 million increase in flow- through depreciation turnaround and $4.6 million of nontax deductible merger related expenditures offset by the elimination of a $23 million deferred tax asset valuation reserve. Federal and state income taxes increased in 1998, primarily due to higher book taxable income, partially offset by an increase in income tax credits primarily due to the Millstone 1 write-off of unrecoverable costs as a result of the February 1999 CL&P rate decision. Gain on Sale of Utility Plant CL&P and WMECO recorded gains on the sale of their fossil and hydroelectric generation assets in 1999. A corresponding amount of amortization expense was recorded. Equity in Earnings of Regional Nuclear Generating and Transmission Companies Equity in earnings of regional nuclear generating and transmission companies decreased in 1999 and 1998, primarily due to lower earnings from the Connecticut Yankee Atomic Power Company. Nuclear Unrecoverable Costs Nuclear unrecoverable costs in 1999 are comprised of one-time charges related to the CL&P write-off of CMEEC nuclear costs ($19.9 million), the CL&P write-off of capital projects as a result of the Connecticut standard offer decision ($11 million), the CL&P/WMECO settlement of Millstone 3 joint owner litigation, net of insurance proceeds ($27 million), the WMECO return disallowed on Millstone 1 unrecovered plant from March 1998 forward ($10.8 million), and the WMECO disallowed Millstone 1 plant per the Massachusetts restructuring order ($2.1 million). In comparison, 1998 is comprised of the write-off of the Millstone 1 entitlement formerly held by CMEEC ($27.8 million) and the write-off of unrecoverable costs as a result of the February 1999 CL&P rate decision ($115.3 million). Other Income/(Loss), Net Other income/(loss), net decreased in 1999, primarily due to the PSNH settlement with the New Hampshire Electric Cooperative ($6.2 million) and the loss on the CL&P assignment of market-based contracts to Select Energy ($15 million). The 1998 increase over 1997 is primarily due to the proceeds resulting from the shareholder derivative suit. -----END PRIVACY-ENHANCED MESSAGE-----