-----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, Hara+IzZz28CdBD9axhtrEYZsJHFCL9UKF8K9VCIBH6ZlvRSqzf55J6pGSPFkB5E aDJsLsGewJiHjS6TM9eE5Q== 0000950109-97-005663.txt : 19970912 0000950109-97-005663.hdr.sgml : 19970912 ACCESSION NUMBER: 0000950109-97-005663 CONFORMED SUBMISSION TYPE: S-1/A PUBLIC DOCUMENT COUNT: 3 FILED AS OF DATE: 19970829 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONNECTICUT LIGHT & POWER CO CENTRAL INDEX KEY: 0000023426 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 060303850 STATE OF INCORPORATION: CT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: S-1/A SEC ACT: SEC FILE NUMBER: 333-30911 FILM NUMBER: 97672380 BUSINESS ADDRESS: STREET 1: 7DELDEN STREET CITY: BERLIN STATE: CT ZIP: 06037-1616 BUSINESS PHONE: 2036655000 S-1/A 1 AMENDMENT NO. 1 TO S-1 As filed with the Securities and Exchange Commission on August 28, 1997 Registration No. 333-30911 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 --------------- Amendment No. 1 to FORM S-1 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 --------------- THE CONNECTICUT LIGHT AND POWER COMPANY (Exact name of registrant as specified in its charter) Connecticut 4911 06-0303850 (State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer of incorporation or Classification Code Number) Identification Number) organization) --------------- Selden Street Berlin, Connecticut 06037 (860) 665-5000 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices) --------------- Robert P. Wax, Senior Vice President, Secretary and General Counsel The Connecticut Light and Power Company Selden Street, Berlin, Connecticut 06037 (860) 665-5000 (Name, address, including zip code, and telephone number, including area code, of agent for service) --------------- Copy to: JEFFREY C. MILLER, Esq. PAULA L. HERMAN, Esq. Northeast Utilities Service Company Day, Berry & Howard P.O. Box 270 CityPlace I Hartford, CT 06141-0270 Hartford, CT 06103-3499 (860) 665-3532 (860) 275-0270 Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement. If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, other than securities offered only in connection with dividend or interest reinvestment plans, check the following box. [ ] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. [ ] --------------- The Registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine. PROSPECTUS Offer For All Outstanding First and Refunding Mortgage Bonds, 1997 Series B Due June 1, 2002 In Exchange For First and Refunding Mortgage 7 3/4% Bonds, 1997 Series C Due June 1, 2002 Each Issued By THE CONNECTICUT LIGHT AND POWER COMPANY ----------------- The Exchange Offer will expire at 5:00 p.m., New York City time, on September 30, 1997 unless extended. ----------------- The Connecticut Light and Power Company, a Connecticut corporation (the Company or CL&P), hereby offers, upon the terms and subject to the conditions set forth in this Prospectus and the accompanying Letter of Transmittal (which together constitute the Exchange Offer), to exchange an aggregate principal amount of up to $200,000,000 of its First and Refunding Mortgage 7 3/4% Bonds, 1997 Series C Due June 1, 2002 (the New Bonds) for a like principal amount of its issued and outstanding First and Refunding Mortgage Bonds, 1997 Series B Due June 1, 2002 (the Old Bonds and together with the New Bonds, the Bonds). The Company will not receive any proceeds from the Exchange Offer and will pay all the expenses incident to the Exchange Offer. The New Bonds will be issued under, and entitled to the benefits of, the Indenture (as defined) governing the Old Bonds. The New Bonds are identical in all material respects to the Old Bonds, except for the elimination of certain transfer restrictions, registration rights and interest rate provisions relating to the Old Bonds. The New Bonds are being offered hereunder in order to satisfy certain obligations of the Company contained in a Registration Rights Agreement dated as of June 19, 1997 (the Registration Rights Agreement). The Company will accept for exchange any and all Old Bonds validly tendered and not withdrawn prior to 5:00 p.m. New York City time on September 30, 1997, unless extended (as so extended, the Expiration Date). The Bonds will mature on June 1, 2002 and will bear interest from June 1, 1997 at the rate of 7 3/4% per annum. Interest will be payable semiannually on June 1 and December 1, commencing December 1, 1997 at the principal office of the Trustee in New York City, to registered owners at the close of business on the May 15 or November 15, as the case may be, preceding such June 1 or December 1, or if such record date is a legal holiday or a day on which banks are authorized to close in New York City, on the next preceding day which is not a legal holiday or a day on which banks are so authorized to close. See "Risk Factors" beginning on page 13 for a discussion of certain risks that should be considered by holders of Old Bonds in considering whether to tender their Old Bonds in the Exchange Offer. THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. September 2, 1997 The New Bonds will be redeemable at the option of the Company, as a whole or in part, at a redemption price equal to the greater of (i) 100% of their principal amount and (ii) the sum of the present values of the remaining scheduled payments of principal and interest thereon discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Yield (as defined), plus in each case accrued interest to the date of redemption. Tenders of Old Bonds pursuant to the Exchange Offer may be withdrawn at any time prior to the Expiration Date. Subject to certain conditions, the Company may terminate the Exchange Offer. In the event the Company terminates the Exchange Offer and does not accept for exchange any Old Bonds, the Company will promptly return the Old Bonds to the Holders thereof. See "The Exchange Offer." The Old Bonds were sold to Morgan Stanley & Co. Incorporated and Salomon Brothers Inc (collectively, the Initial Purchasers) in the Original Offering (as defined), in a transaction not registered under the Securities Act of 1933, as amended (the Securities Act), in reliance upon the exemption provided in Section 4(2) of the Securities Act. The Initial Purchasers subsequently placed the Old Bonds with "qualified institutional buyers," as defined in Rule 144A under the Securities Act. Accordingly, the Old Bonds may not be reoffered, resold or otherwise transferred in the United States unless so registered or unless an applicable exemption from the registration requirements of the Securities Act is available. The New Bonds are being offered hereunder in order to satisfy the obligations of the Company under the Registration Rights Agreement. Based on interpretations by the staff of the Securities and Exchange Commission (the Commission) issued to other issuers in similar contexts, New Bonds issued pursuant to the Exchange Offer in exchange for Old Bonds may be offered for resale, resold and otherwise transferred by holders thereof (other than any such holder which is an "affiliate" of the Company within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act provided that such New Bonds are acquired in the ordinary course of such holders' business and such holders have no arrangement with any person to participate in the distribution of such New Bonds. Each broker-dealer that receives New Bonds for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of such New Bonds. The Letter of Transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This Prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of New Bonds received in exchange for Old Bonds where such Old Bonds were acquired as a result of market-making activities or other trading activities. The Company has agreed, for a period of 180 days after the Expiration Date, that it will make this Prospectus available to any broker-dealer for use in connection with any such resale. See "Plan of Distribution." Prior to this Exchange Offer, there has been no public market for the New Bonds. The Company does not intend to list the New Bonds on any securities exchange or to seek approval for quotation through any automated quotation system. There can be no assurance that an active market for the New Bonds will develop. See "Risk Factors--Market for the New Bonds." Moreover, to the extent that Old Bonds are tendered and accepted in the Exchange Offer, the trading market for untendered and tendered but unaccepted Old Bonds could be adversely affected. If a market for the New Bonds should develop, the New Bonds could trade at a discount from their face amount. There can be no assurance that an active public market for the New Bonds will develop. Holders whose Old Bonds are not tendered and accepted in the Exchange Offer will continue to hold such Old Bonds and will be entitled to all the rights and preferences, and will be subject to the limitations applicable thereto under the Indenture (as herein defined) and, with respect to transfer, under the Securities Act. See "Risk Factors--Consequences of Failure to Exchange." -2- THIS PROSPECTUS (PROSPECTUS) DOES NOT CONSTITUTE AN OFFER TO SELL, OR THE SOLICITATION OF AN OFFER TO BUY, ANY OF THE NEW BONDS OFFERED HEREBY BY ANY PERSON IN ANY JURISDICTION IN WHICH IT IS UNLAWFUL FOR SUCH PERSON TO MAKE AN OFFERING OR A SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL UNDER ANY CIRCUMSTANCES IMPLY THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY OR THAT THE INFORMATION SET FORTH HEREIN IS CORRECT AS OF ANY DATE SUBSEQUENT TO THE DATE HEREOF. IN MAKING AN INVESTMENT DECISION, INVESTORS MUST RELY ON THEIR OWN EXAMINATION OF THE COMPANY AND THE TERMS OF THE NEW BONDS, INCLUDING THE MERITS AND RISKS INVOLVED. THESE SECURITIES HAVE NOT BEEN RECOMMENDED, APPROVED OR DISAPPROVED BY ANY FEDERAL OR STATE SECURITIES COMMISSION OR REGULATORY AUTHORITY. FURTHERMORE, THE FOREGOING AUTHORITIES HAVE NOT CONFIRMED THE ACCURACY OR DETERMINED THE ADEQUACY OF THIS DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. THE COMPANY IS NOT MAKING ANY REPRESENTATION TO ANY OFFEREE OR PURCHASER OF THE NEW BONDS REGARDING THE LEGALITY OF AN INVESTMENT BY SUCH OFFEREE OR PURCHASER UNDER APPROPRIATE LEGAL INVESTMENT OR SIMILAR LAWS. EACH INVESTOR SHOULD CONSULT WITH HIS OWN ADVISORS AS TO LEGAL, TAX, BUSINESS, FINANCIAL AND RELATED ASPECTS OF A PURCHASE OF THE NEW BONDS. ------------------- -3- AVAILABLE INFORMATION The Company has filed with the Commission a Registration Statement on Form S-1 (the Registration Statement) under the Securities Act for the registration of the New Bonds offered hereby. This Prospectus, which constitutes a part of the Registration Statement, does not contain all the information set forth in the Registration Statement, certain portions of which are omitted from the Prospectus as permitted by the rules and regulations of the Commission. For further information with respect to the Company and the New Bonds offered hereby, reference is made to the Registration Statement, including the exhibits thereto, and financial statements and notes filed as a part thereof. Statements made in this Prospectus concerning the contents of any documents referred to herein are not necessarily complete. With respect to each such document filed with the Commission as an exhibit to the Registration Statement, reference is made to the exhibit for a more complete description of the matter involved, and each such statement shall be deemed qualified in its entirety by such reference. The Company is subject to the periodic reporting and certain other informational requirements of the Securities Exchange Act of 1934, as amended (Exchange Act) and files periodic reports and other information with the Commission. The Registration Statement in which this Prospectus is included and the exhibits and schedules thereto, as well as such reports and other information filed by the Company with the Commission may be inspected and copied at prescribed rates, at the public reference facility of the Commission, at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, or at the Commission's regional offices at 7 World Trade Center, 13th Floor, New York, New York 10048, and CitiCorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of such material also can be obtained by mail from the public reference facilities of the Commission, at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates. In addition, the aforementioned material can be inspected at the offices of The New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005. The Commission also maintains a Website that contains reports and other information regarding registrants, such as the Company, that file electronically with the Commission. The address of such site is (http://www.sec.gov/). Anyone who receives this Prospectus may obtain a copy of the Indenture and the Registration Rights Agreement (as defined herein) without charge by writing to Theresa H. Allsop, Assistant Secretary, at the Company's principal executive offices at Selden Street, Berlin, Connecticut 06037-1616 or by telephone at 860/665-3019. FORWARD-LOOKING STATEMENTS Certain statements contained in this Prospectus are "forward- looking statements" within the meaning of the Securities Act and the Exchange Act, such as forecasts and projections of expected future performance or statements of plans and objectives of the Company and/or the Northeast Utilities (NU) system (NU system). Although such forward-looking statements have been based -4- on reasonable assumptions, there is no assurance that the expected results will be achieved, and actual results could differ materially from these statements. Some of the factors that could cause actual results to differ materially include, but are not limited to: governmental and regulatory actions and initiatives; the impact of deregulation and increased competition in the industry; generating plant performance; weather conditions; fuel prices and availability; general economic conditions, including the effects of inflation; and technological changes. -5- PROSPECTUS SUMMARY The following material is qualified in its entirety by, and should be considered in conjunction with, the detailed information and financial statements appearing elsewhere in this Prospectus. The Company The Company, a Connecticut corporation organized in 1907, is a wholly-owned subsidiary of NU. The Company is the largest electric utility in Connecticut and is engaged principally in the production, purchase, transmission, distribution and sale of electricity at retail for residential, commercial, industrial and municipal purposes to approximately 1.1 million customers in 149 cities and towns in Connecticut. The Exchange Offer Old Bonds............... The Old Bonds were sold by the Company to the Initial Purchasers on June 26, 1997 (the Issue Date) pursuant to an exemption from or in transactions not subject to the registration requirements of the Securities Act and applicable state securities laws. The Initial Purchasers resold the Old Bonds to "qualified institutional buyers," as defined in Rule 144A under the Securities Act. The Registration Statement of which this Prospectus is a part relates only to the registration of the New Bonds in exchange for the Old Bonds. Registration Rights..... The Company and the Initial Purchasers entered into a Registration Rights Agreement, dated as of June 19, 1997 (Registration Rights Agreement), which grants the holders of the Old Bonds certain exchange and registration rights. The New Bonds are being offered hereunder in order to satisfy the obligations of the Company under the Registration Rights Agreement. The Exchange Offer...... Up to $200,000,000 aggregate principal amount of the New Bonds are being offered in exchange for a like principal amount of the Old Bonds. No accrued interest will be paid on the Old Bonds upon the exchange thereof, but interest will accrue on the New Bonds from June 1, 1997. Holders of the Old Bonds to whom this Exchange Offer is made have special rights under the Registration Rights Agreement that will terminate upon the consummation of the Exchange Offer. For procedures for tendering the Old Bonds, see "The Exchange Offer." -6- Based on interpretations by the staff of the Commission set forth in certain no-action letters issued by the Commission to third parties, the Company believes that New Bonds issued pursuant to the Exchange Offer in exchange for Old Bonds may be offered for resale, resold and otherwise offered by any holder thereof (other than any such holder that is an "affiliate" of the Company within the meaning of Rule 405 under the Securities Act) without compliance with the registration and (except as set forth below) the prospectus delivery provisions of the Securities Act, provided that such New Bonds are acquired in the ordinary course of such holder's business and that such holder does not intend to participate and has no arrangement or understanding with any person to participate in the distribution of such New Bonds. Both (i) Broker-dealers and (ii) holders of Old Bonds who are considering tendering Old Bonds in order to participate in the distribution of the New Bonds should see "Risk Factors--Consequences of Failure to Exchange,""The Exchange Offer--Purpose and Effect of the Exchange Offer" and "--Resales of the New Bonds" and "Plan of Distribution" for information concerning certain requirements that may apply to their activities. New Bonds............... The New Bonds are identical in all material respects to the Old Bonds, except for the elimination of certain transfer restrictions, registration rights and interest rate provisions. The New Bonds will be represented by a global security registered in the name of The Depository Trust Company (DTC) or its nominee. Book- entry interests in the global security will be shown on, and transfers thereof will be effected only through, records maintained by DTC or its nominee. Conditions of the Exchange Offer......... The Exchange Offer is not conditioned upon any minimum principal amount of Old Bonds being tendered for exchange except that Old Bonds may be tendered only in integral multiples of US$1,000 principal amount. Notwithstanding any other provision of the Exchange Offer, the Company shall not be required to accept for exchange, or to issue New Bonds in exchange for, any Old Bonds and may terminate or amend the Exchange Offer, at any time prior to the consummation of the Exchange Offer if: (i) the Exchange Offer would violate applicable law or any applicable interpretation of the staff of the Commission, (ii) an action or proceeding is instituted or threatened in any court or by any governmental agency which -7- might materially impair the ability of the Company to proceed with the Exchange Offer or a material adverse development has occurred in any existing action or proceeding with respect to the Company, or (iii) all governmental approvals which the Company deems necessary for the consummation of the Exchange Offer have not been obtained. See "The Exchange Offer-- Certain Conditions to the Exchange Offer." Tenders; Expiration Date; Withdrawal....... The Exchange Offer will expire at 5:00 p.m., New York City time, on September 30, 1997, or such later date and time to which it is extended (as so extended, the Expiration Date). The tender of Old Bonds pursuant to the Exchange Offer may be withdrawn at any time prior to the Expiration Date. Any Old Bonds not accepted for exchange for any reason will be returned without expense to the tendering holder thereof as promptly as practicable after expiration or termination of the Exchange Offer. Procedures for Tendering Old Bonds.............. Each holder of Old Bonds desiring to accept the Exchange Offer must complete and sign the Letter of Transmittal in accordance with the instructions contained herein and therein, and mail or deliver the Letter of Transmittal, together with the Old Bonds and any other required documents to the Exchange Agent (as defined herein) at the address set forth herein and in the Letter of Transmittal prior to 5:00 p.m., New York City time, on the Expiration Date. By executing the Letter of Transmittal, each holder will represent to the Company that, among other things, the New Bonds acquired pursuant to the Exchange Offer are being obtained in the ordinary course of business of the person receiving such New Bonds, whether or not such person is the holder, that neither the holder nor any such other person has any arrangement or understanding with any person to participate in the distribution of such New Bonds and that neither the holder nor any such other person is an "affiliate" of the Company, as defined under Rule 405 of the Securities Act. Consequences of Failure to Exchange............ Holders of Old Bonds eligible to participate who do not exchange their Old Bonds for New Bonds pursuant to the Exchange Offer will not have any further registration rights and such Old Bonds will continue to be subject to the restrictions on -8- transfer as set forth in the legend thereon as a consequence of the issuance of the Old Bonds pursuant to exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Company does not currently anticipate that it will register the Old Bonds under the Securities Act. Accordingly, the market for such Old Bonds could be highly illiquid. See "Risk Factors-Consequences of Failure to Exchange." Guaranteed Delivery Procedures............. Holders of Old Bonds who wish to tender their Old Bonds and (i) whose Old Bonds are not immediately available or (ii) who cannot deliver their Old Bonds, the Letter of Transmittal and any other documents required by the Letter of Transmittal to the Exchange Agent (or comply with the procedures for book-entry transfers) prior to 5:00 p.m., New York City time, on the Expiration Date, must tender their Old Bonds according to the guaranteed delivery procedures set forth in "The Exchange Offer-- Guaranteed Delivery Procedures." Acceptance of Old Bonds and Delivery of New Bonds.................. Subject to the satisfaction or waiver of all conditions of the Exchange Offer, the Company will accept for exchange any and all Old Bonds that are properly tendered in the Exchange Offer prior to 5:00 p.m., New York City time, on the Expiration Date. The New Bonds issued pursuant to the Exchange Offer will be delivered in exchange for the applicable Old Bonds accepted in the Exchange Offer promptly following the Expiration Date. See "The Exchange Offer--Acceptance of Old Bonds for Exchange; Delivery of New Bonds." Federal Income Tax Consequences........... The exchange pursuant to the Exchange Offer will not result in any income, gain or loss to the holders of the Bonds or the Company for federal income tax purposes. See "Certain Federal Income Tax Considerations." Use of Proceeds......... There will be no cash proceeds to the Company from the exchange pursuant to the Exchange Offer. Exchange Agent.......... Bankers Trust Company has agreed to act as Exchange Agent for the Exchange Offer. -9- Summary Description of the New Bonds Interest Rate........... 7 3/4% per annum. Interest Payment Dates.. June 1 and December 1, commencing December 1, 1997 Maturity................ June 1, 2002. Security................ The New Bonds will be secured by the Indenture (as defined herein), which constitutes a first mortgage lien (subject to liens permitted by the Indenture, including liens and encumbrances existing at the time of acquisition by the Company) on substantially all of the Company's physical property and franchises, including the Company's generating stations (but not including the Company's interest in the plants of the four regional nuclear generating companies described herein) and its transmission and distribution facilities. Optional Redemption..... The New Bonds will be redeemable at any time on not less than 30 days notice by the Company, in whole or in part, at a redemption price equal to the greater of (i) 100% of the principal amount thereof, and (ii) the sum of the present values of the remaining scheduled payments of principal and interest thereon, plus accrued interest to the date of redemption, if any. See "Description of the New Bonds--Redemption Provisions." Sinking Fund Redemption. There will be no sinking fund requirements. Form and Denomination... The New Bonds will be issued in fully registered form without coupons in denominations of US$1,000 and integral multiples thereof. The New Bonds will be represented by a single permanent Global Security, registered in the name of Cede & Co., as nominee of DTC. See "Book-Entry; Delivery and Form." Use of Proceeds......... The Company will receive no cash proceeds from the issuance of the New Bonds. The net proceeds from the sale of the Old Bonds were or will be used for the repayment of the Company's short term debt incurred for general working capital purposes, including costs associated with the current outages at Millstone. For additional information regarding the New Bonds, see "Description of the New Bonds." -10- Risk Factors See "Risk Factors" beginning on page 13 for a discussion of certain risks that should be considered by holders of Old Bonds in evaluating whether to tender the Old Bonds. -11- Summary Consolidated Financial Data (thousands, except percentages and ratios)
12 Months Ended June 30, 1997 Year Ended December 31, -------------- ---------------------------------- (unaudited) 1996 1995 1994 ---------- ---------- ---------- Income Summary: Operating Revenues.............. $2,394,854 $2,397,460 $2,387,069 $2,328,052 Operating (Loss) Income......... (55,840) 29,773 324,026 286,948 Net (Loss) Income.............. (172,908) (80,237) 205,216 198,288 Total Assets (end of period).. $6,399,072 $6,244,036 $6,045,631 $6,217,457
As of June 30, 1997 ---------------------------------------------- (unaudited) As % of Adjusted Actual Adjusted (a) Capitalization ---------- ------------ -------------- Capitalization Summary: Long-Term Debt (including current maturities)............................. $2,044,077 $2,044,077 57.66% Preferred Stock Subject to Mandatory Redemption.............................. 155,000 155,000 4.37% Preferred Stock Not Subject to Mandatory Redemption.................... 116,200 116,200 3.28% Common Stockholder's Equity.............. 1,230,014 1,230,014 34.69% ========== ============ ============== Total Capitalization $3,545,291 $3,545,291 100.00% ========== ============ ===============
12 Months Ended June 30, 1997 Year Ended December 31, --------------- ------------------------------------------------------------ (unaudited) 1996 1995 1994 1993 1992 ---------- ---------- ---------- ---------- ---------- Ratio of Earnings to Fixed Charges (c)........................... (0.67)(b) 0.30(b) 3.64 3.65 2.71 2.96
(a) Because the New Bonds will be exchanged for issued and outstanding Old Bonds, the New Bonds will not increase the amount of the Company's outstanding total long-term debt. (b) For the twelve-month periods ended December 31, 1996 and June 30, 1997, the ratio of earnings to fixed charges reflects the effects of additional costs, including replacement power costs, associated with the outages at the three Millstone units. For such periods, earnings were inadequate to cover fixed charges; the additional earnings required to bring the ratio of earnings to fixed charges to 1.0 for such periods would have been $102,872,000 and $256,769,000, respectively. See "Risk Factors." (c) The "Earnings" component of the "Ratio of Earnings to Fixed Charges" represents the aggregate of net income or loss, taxes based on income, investment tax credit adjustments, and fixed charges. "Fixed Charges" represent the aggregate of interest (whether capitalized or expensed), related amortizations, and the interest component of leases. -12- RISK FACTORS Prospective investors should consider carefully all of the information set forth in this Prospectus, including the following risks, before investing in the New Bonds. Nuclear Plant Outages and Liquidity As a result of the prolonged outages at the three Millstone nuclear units (Millstone) located in Waterford, Connecticut, the Company faced an extremely difficult year in 1996 and continues to face some of the most severe regulatory scrutiny and financial challenges in the history of the United States nuclear industry, including numerous civil lawsuits and criminal investigations and regulatory proceedings, requesting among other things license revocation. These outages have resulted in significantly increased expenditures for replacement power and work undertaken at Millstone. The length of the outages and the high costs of the recovery efforts weakened the Company's 1996 earnings, balance sheet and cash flows and continue to have an adverse impact on the Company's financial condition. The Company currently anticipates that Millstone 3 will be ready for restart by the end of the third quarter of 1997, Millstone 2 in the fourth quarter of 1997 and Millstone 1 in the first quarter of 1998. Because of the need for completion of independent inspections and reviews and for the Nuclear Regulatory Commission (NRC) to complete its processes before the NRC Commissioners can vote on permitting a unit to restart, the actual beginning of operations is expected to take several months beyond the time when a unit is declared ready for restart. The NRC's internal schedules at present indicate that a meeting of the Commissioners to act upon a Millstone 3 restart request could occur by mid-December if NU, the independent review teams and NRC staff concur that the unit can return to operation by that time. A similar schedule indicates a mid-March meeting of the Commissioners to act upon a Millstone 2 restart request. Management hopes that Millstone 3 can begin operating by the end of 1997. There can be no assurances, however, that the Company's expectations will be met. If the return to service of one or more of the Millstone units is delayed substantially, or if any needed waivers or modifications to the Company's financing arrangements are not forthcoming on reasonable terms, or if the Company encounters additional significant costs or other significant deviations from management's current assumptions, resulting in the Company's inability to meet its cash requirements, management would take actions to reduce costs and to obtain additional sources of funds. The availability of these funds would be dependent upon general market conditions and the Company's and the NU system's credit and financial condition at that time. Both Moody's Investors Service (Moody's) and Standard and Poor's Corporation (S&P) have recently downgraded the Company's senior debt to Ba1 and BB+, respectively. Management has committed not to seek recovery of the portion of these costs attributable to the failure to meet industry standards in operating Millstone. In light of that commitment, and in recognition of the NRC's watch list designation of Millstone and that numerous internal and external reports have been critical of the operation of Millstone, management has said that the Company will not seek recovery for a substantial portion of such costs. While the Company -13- believes that it is entitled to recovery of a portion of the costs that have been and will be incurred, and intends to apply for recovery of such costs, the Connecticut Department of Public Utility Control (DPUC) on June 27, 1997 orally granted summary judgment in a prudence proceeding disallowing recovery by the Company of substantially all of its Millstone outage related costs. On July 30, 1997, the DPUC issued a purported "written decision" in the same case, which disallowed recovery of an estimated $600 million of replacement power costs related to the Millstone outages, and found that the Company had waived recovery of an additional $360 million of incremental operations and maintenance (O&M). The written decision, like the oral decision, recognized the Company's right to seek recovery, in a future rate proceeding, of $40 million related to reliability enhancements. The Company has appealed the DPUC's decision. Management currently does not intend to request any such cost recoveries until after the Millstone units begin returning to service, so it is unlikely that any additional revenues from any permitted recovery of these costs will be available while the units are out of service to contribute to funding the recovery efforts. Any requests for recovery would include only costs for projects the Company would have undertaken under normal operating conditions or that provide long-term value for the Company customers. In a separate proceeding, the DPUC ordered the Company to submit studies by July 1, 1997 that analyze the economic benefits from continued operation of Millstone 1 and 2. On July 1, 1997, the Company submitted continued unit operation studies to the DPUC showing that, under base case assumptions, Millstone 1 will have a value to NU system customers (as compared to the cost of shutting down the unit and incurring replacement power costs) of approximately $70 million during the remaining thirteen years of its operating license and Millstone 2 will have a value to NU system customers (on the same assumptions as used with Millstone 1) of approximately $500 million during the remaining eighteen years of its operating license. Two other cases submitted to the DPUC based on higher assumed O&M costs, which the Company considers less likely, indicated that Millstone 1 would be uneconomic in varying degrees. Based on these economic analyses, the Company expects to continue operating both Millstone 1 and Millstone 2 for the remaining terms of their respective operating licenses. The DPUC has stated it will consider these analyses in the context of the Company's next integrated resource planning proceeding which begins in April 1998. The Company cannot predict the outcome of this proceeding. In addition, the DPUC is required to review a utility's rates every four years if there has not been a rate proceeding during such period. On June 16, 1997, the Company filed with the DPUC certain financial information consistent with the DPUC's filing requirements applicable to such four year review. The Company expects hearings before the DPUC with respect to such review could begin as early as September, 1997. The Company cannot predict the outcome of this proceeding. On August 7, 1997, the non-NU owners of Millstone 3 filed demands for arbitration with the Company and Western Massachusetts Electric Company (WMECO) as well as lawsuits in Massachusetts Superior Court against NU and its current and former trustees. The non-NU owners raise a number of contract, tort and statutory claims, arising out of the operation of Millstone 3. The arbitrations and lawsuits seek to recover compensatory damages, punitive damages, treble damages and attorneys' fees. Owners representing approximately two-thirds of the non-NU interests in Millstone 3 have claimed compensatory damages in excess of $200 million. In addition, one of the -14- lawsuits seeks to restrain NU from disposing of its shares of the stock of WMECO and Holyoke Water Power Company (HWP), pending the outcome of the lawsuit. The NU companies believe there is no legal basis for the claims and intend to defend against them vigorously. Each major company in the NU system finances its own needs. Neither the Company nor WMECO has any agreements containing cross defaults based on events or occurrences involving NU, Public Service Company of New Hampshire (PSNH) or North Atlantic Energy Corporation (NAEC). Similarly, neither PSNH nor NAEC has any agreements containing cross defaults based on events or occurrences involving NU, the Company or WMECO. Nevertheless, it is possible that investors will take negative operating results or regulatory developments at one company in the NU system into account when evaluating other companies in the NU system. That could, as a practical matter and despite the contractual and legal separations among the NU companies, negatively affect each company's access to the financial markets. If the return to service of one or more of the Millstone units is delayed substantially, or if some borrowing facilities become unavailable because of difficulties in meeting borrowing conditions, or if the NU system encounters additional significant costs or any other significant deviations from management's current assumptions, the currently available borrowing facilities could be insufficient to meet all of the NU system's cash requirements. In those circumstances, management would take actions to reduce costs and cash outflows and would attempt to take other actions to obtain additional sources of funds. The availability of these funds would be dependent upon the general market conditions and the NU system's credit and financial condition at the time. For more information, see "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business--Overview of Nuclear and Related Financial Matters," "--Electric Operations--Nuclear Plant Performance and Regulatory Oversight," "--Competition and Cost Recovery," "--Rates" and "--Financing Program--Financing Limitations," and "Legal Proceedings." Industry Restructuring and Competition Competition in the energy industry continues to grow as a result of legislative and regulatory action, technological advances, relatively high electric rates in certain regions of the country, including New England, surplus generating capacity and the increased availability of natural gas. These competitive pressures are particularly strong in the NU system's service territories, where legislators and regulatory agencies have been at the forefront of the restructuring movement. Changes in the industry are expected to place downward pressure on prices and to increase customer choice through competition. Although the Company continues to operate predominantly in a state-approved franchise territory under traditional cost-of-service regulation, restructuring initiatives in the State of Connecticut have created uncertainty with respect to future rates and the recovery of "strandable investments." Strandable investments are expenditures that have been made by utilities in the past to meet their public service obligations, with the expectation that they would be recovered from -15- customers in the future. However, under certain circumstances these costs might not be recoverable from customers in a fully competitive electric utility industry. The Company continues to believe such costs will be recoverable. The Company is particularly vulnerable to strandable investments because of (i) the Company's relatively high investment in nuclear generating capacity, which had a high initial cost to build, (ii) state-mandated purchased power arrangements priced above market, and (iii) significant regulatory assets, which are those costs that have been deferred by state regulators for future collection from customers. As of June 30, 1997, the Company's net investment in nuclear generating capacity, excluding its investment in certain regional nuclear companies, was approximately $2.3 billion, and its regulatory assets were approximately $1.2 billion. The Company's exposure to strandable investments and above- market purchased power obligations exceeds its shareholder's equity. The Company's ability to compete in a restructured environment would be negatively affected unless the Company were able to recover substantially all of the past investments and commitments. Unless amortization levels are changed from currently scheduled rates, the Company's regulatory assets are expected to be substantially decreased over the next five years. For more information regarding electric industry restructuring, see "Business--Competition and Cost Recovery," "Business--Rates" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." Regulatory Accounting and Assets The accounting policies of the Company conform to generally accepted accounting principles applicable to rate regulated enterprises and reflect the effects of the ratemaking process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered through future revenues. Through their actions, regulators may also reduce or eliminate the value of an asset, or create a liability. Recently, the Commission has questioned the ability of certain utilities to continue to follow SFAS No. 71 in light of state legislation regarding the transition to retail competition. The industry expects guidance on this issue from the Financial Accounting Standards Board's Emerging Issues Task Force in the near future. The Company is not yet subject to a transition plan. Criteria that could give rise to discontinuation of the application of SFAS No. 71 include: (1) increasing competition which significantly restricts the Company's ability to charge prices which allow it to recover operating costs, earn a fair return on invested capital and recover the amortization of regulatory assets, and (2) a significant change in the manner in which rates are set by the DPUC from cost-based regulation to some other form of regulation. In the event the Company determines it no longer meets the criteria for following SFAS No. 71, the Company would be required to write off its regulatory assets and liabilities. At June 30, 1997, the Company's regulatory assets were approximately $1.2 billion. In addition, the Company would be required to evaluate whether the changes in the competitive and regulatory environment which led to discontinuing the application of SFAS No. 71 would also result in an impairment of the net book value of the Company's long- -16- lived assets in accordance with SFAS No. 121, "Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to be Disposed Of." SFAS No. 121 requires the evaluation of long-lived assets, including regulatory assets, for impairment when certain events occur or when conditions exist that indicate the carrying amounts of assets may not be recoverable. SFAS No. 121 requires that any long-lived assets which are no longer probable of recovery through future revenues be revalued based on estimated future cash flows. If the revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. Management continues to believe that it is probable that the Company will recover its investments in long-lived assets, including regulatory assets, through future revenues. This conclusion may change in the future as competitive factors influence wholesale and retail pricing in the electric utility industry or if the cost-of-service based regulatory structure were to change. Environmental Regulation The Company is subject to federal, state and local regulations with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Similarly, the Company's major generation and transmission facilities may not be constructed or significantly modified without a review by the applicable state agency of the environmental impact of the proposed construction or modification. See "Business--Other Regulatory and Environmental Matters--Environmental Regulation." Environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations, and other facilities. Changing environmental requirements could also require extensive and costly modifications to the Company's existing generating units and transmission and distribution systems, and could limit operations and/or raise operating costs significantly. As a result, the Company may incur significant additional environmental costs, greater than amounts included in reserves, in connection with the generation and transmission of electricity and the storage, transportation and disposal of by-products and wastes. The Company may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. The cumulative long-term cost impact of increasingly stringent environmental requirements cannot accurately be estimated. Market for the New Bonds The New Bonds are a new issue of securities with no established trading market, and the Company does not intend to apply for listing of the New Bonds on a national securities exchange, but has been advised by the Initial Purchasers that they presently intend to make a market in the New Bonds, as permitted by applicable law and regulations. The Initial Purchasers are not obligated, however, to make a market in the New Bonds, and any such market making may be discontinued at any time at the sole discretion of the Initial Purchasers. Accordingly, no assurance can be given as to the liquidity of the trading market for the New Bonds. -17- Consequences of Failure to Exchange Holders of Old Bonds who do not participate in the Exchange Offer will continue to be subject to the restrictions on transfer of the Old Bonds as set forth in the legend thereon. In general, the Old Bonds may not be offered or sold, unless registered under, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. The Company does not currently anticipate that it will register the Old Bonds under the Securities Act. Based on interpretations of the Securities Act by the staff of the Commission, New Bonds issued pursuant to the Exchange Offer in exchange for Old Bonds may be offered for resale, resold, or otherwise transferred by holders thereof (other than any such holder which is an "affiliate" of the Company within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that such New Bonds are acquired in the ordinary course of such holders' business and such holders have no arrangement with any person to participate in the distribution of such New Bonds. Notwithstanding the foregoing, each broker-dealer that receives New Bonds for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of such New Bonds. The Letter of Transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This Prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with any resale of New Bonds received in exchange for Old Bonds where such Old Bonds were acquired by such broker- dealer as a result of market-making activities or other trading activities (other than Old Bonds acquired directly from the Company). The Company has agreed that, for a period of 180 days from the consummation of the Exchange Offer, it will make this Prospectus available to any broker-dealer for use in connection with any such resale. See "Plan of Distribution." Compliance with Exchange Offer Procedures To participate in the Exchange Offer and to avoid the restrictions on transfer of the Old Bonds, holders of Old Bonds must transmit a properly completed Letter of Transmittal, including all other documents required by such Letter of Transmittal, to the Exchange Agent at the address set forth below under "The Exchange Offer--Exchange Agent" on or prior to the Expiration Date. In addition, either (i) certificates for such Old Bonds must be received by the Exchange Agent along with the Letter of Transmittal, or (ii) a timely confirmation of a book-entry transfer of such Old Bonds, if such procedure is available, into the Exchange Agent's account at the DTC pursuant to the procedure for book-entry transfer described herein, must be received by the Exchange Agent prior to the Expiration Date, or (iii) the holder must comply with the guaranteed delivery procedures described herein. THE COMPANY The Company, a Connecticut corporation organized in 1907, is a wholly-owned subsidiary of NU. Four wholly-owned operating subsidiaries of NU--the Company, PSNH, WMECO and HWP--furnish electric service in portions of Connecticut and New Hampshire and in western -18- Massachusetts. A fifth wholly-owned subsidiary of NU, NAEC, owns a 35.98 percent interest in the Seabrook nuclear generating facility (Seabrook) in Seabrook, New Hampshire and sells its share of the output and capacity of Seabrook to PSNH. The Company is the largest electric utility in Connecticut and is engaged principally in the production, purchase, transmission, distribution and sale of electricity at retail for residential, commercial, industrial and municipal purposes to approximately 1.1 million customers in 149 cities and towns in Connecticut. The principal executive offices of the Company are located at Selden Street, Berlin, Connecticut 06037-1616 (telephone 860/665-5000). THE ORIGINAL OFFERING On June 26, 1997, in the Original Offering, the Company issued and sold to the Initial Purchasers $200,000,000 in aggregate principal amount of the Old Bonds. The Old Bonds were sold pursuant to exemptions from or in transactions not subject to the registration requirements of the Securities Act and applicable state securities laws. The Initial Purchasers subsequently placed the Old Bonds with "qualified institutional buyers," as defined in Rule 144A under the Securities Act. See "The Exchange Offer." The Company received approximately $197 million of net proceeds from the Original Offering. The entire net proceeds of the Original Offering have been used for general working capital purposes, including payment of costs associated with the current outages at Millstone. THE EXCHANGE OFFER Purpose and Effect of the Exchange Offer The Old Bonds were sold to Initial Purchasers in the Original Offering in a transaction not registered under the Securities Act, in reliance upon the exemption provided in Section 4(2) of the Securities Act. The Initial Purchasers subsequently placed the Old Bonds with "qualified institutional buyers," as defined in Rule 144A under the Securities Act. Accordingly, the Old Bonds may not be reoffered, resold or otherwise transferred in the United States unless so registered or unless an applicable exemption from the registration requirements of the Securities Act is available. The New Bonds are being offered hereunder in order to satisfy the obligations of the Company under the Registration Rights Agreement. Capitalized terms used under this heading and not otherwise defined shall have the meaning set forth in the Registration Rights Agreement. Pursuant to the Registration Rights Agreement, the Company agreed, for the benefit of the holders of the Old Bonds, that (i) unless the Exchange Offer would not be permitted by applicable law or Commission policy, the Company would use its best efforts to have a registration statement (the Exchange Offer Registration Statement) on the appropriate form under the Securities Act, with respect to an offer to exchange the Old Bonds for a like aggregate amount of New Bonds declared effective by the Commission on or prior to 150 days after the date of original issuance of the Old Bonds (the Issue Date) and (ii) if obligated to file the Shelf Registration Statement (defined below), the Company will file prior to 30 days after such filing obligation arises and use its best efforts to -19- cause the Shelf Registration Statement to be declared effective by the Commission on or prior to 150 days after such obligation arises. The Registration Statement of which this Prospectus is a part is intended to satisfy the Company's obligation to file an Exchange Offer Registration Statement. In the event that any change in law or currently prevailing interpretations of law by the Commission's staff do not permit the Company to effect the Exchange Offer, or if for any reason the Exchange Offer is not consummated within 180 days of the Issue Date and the holders of a majority in principal amount of the Old Bonds so request, or if a holder of the Old Bonds notifies the Company that (a) due to a change in law or policy it is not entitled to participate in the Exchange Offer; (b) due to a change in law or policy it may not resell the Exchange Bonds acquired by it in the Exchange Offer to the public without delivering a prospectus and the prospectus contained in the Exchange Offer Registration Statement is not appropriate or available for such resales by such Holder or (c) it is a broker-dealer and owns Bonds acquired directly from the Company or any affiliate of the Company, the Company agreed to use its best efforts to cause to be filed a registration statement (the Shelf Registration Statement) with respect to the resale of such Old Bonds or New Bonds, as the case may be. The Company further agreed to use its best efforts to keep such Shelf Registration Statement continuously effective, supplemented and amended until the second anniversary of the Issue Date or such shorter period that will terminate when all the Old Bonds covered by the Shelf Registration Statement have been sold pursuant thereto or cease being Bonds. If (a) the Company fails to consummate the Exchange Offer within 180 days after the Issue Date, or (b) the Shelf Registration Statement or the Exchange Offer Registration Statement is declared effective but thereafter, subject to certain exceptions, ceases to be effective or usable in connection with the Exchange Offer or resales of Old Bonds, as the case may be, during the periods specified in the Registration Rights Agreement (each such event referred to in clauses (a) and (b) above, a Registration Default), then the interest rate on transfer restricted bonds will increase (Additional Interest), with respect to the first 90-day period immediately following the occurrence of such Registration Default by 0.50% per annum and will increase by an additional 0.50% per annum with respect to each subsequent 90-day period until all Registration Defaults have been cured, up to a maximum amount of 1.50% per annum. Following the cure of all Registration Defaults, the accrual of Additional Interest will cease and the interest rate will revert to the original rate. Based on interpretations by the staff of the Commission issued to other issuers in similar contexts, the Company believes that New Bonds issued pursuant to the Exchange Offer in exchange for Old Bonds may be offered for resale, resold and otherwise transferred by any holder of such New Bonds (other than any such holder which is an "affiliate" of the Company within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that such New Bonds are acquired in the ordinary course of such holder's business and such holder has no arrangement or understanding with any person to participate in the distribution of such New Bonds. Each holder is required to acknowledge in the Letter of Transmittal that it is not engaged in, and does not intend to engage in, a distribution of the New Bonds. Any holder who tenders in the Exchange Offer for the purpose of participating -20- in a distribution of the New Bonds must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction. Each broker-dealer that receives New Bonds for its own account pursuant to the Exchange Offer will also be required to acknowledge that (i) Old Bonds tendered by it in the Exchange Offer were acquired in the ordinary course of its business as a result of market-making or other trading activities, and (ii) it will deliver a prospectus in connection with any resale of New Bonds received in the Exchange Offer. The Letter of Transmittal will also state that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This Prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of New Bonds received in exchange for Old Bonds where such Old Bonds were acquired by such broker-dealer as a result of market-making activities or other trading activities (other than Old Bonds acquired directly from the Company). The Company has agreed that, for a period of 180 days after Consummation of the Exchange Offer, it will make this Prospectus available to any broker-dealer for use in connection with any such resale. See "Plan of Distribution." Notwithstanding the foregoing, based on the above-mentioned interpretations by the staff of the Commission, the Company believes that broker-dealers who acquired the Old Bonds directly from the Company and not as a result of market-making activities or other trading activities cannot rely on such interpretations by the staff of the Commission and must, in the absence of an exemption, comply with the registration and prospectus delivery requirements of the Securities Act in connection with secondary resales of the New Bonds. Such broker-dealers may not use this Prospectus, as it may be amended or supplemented from time to time, in connection with any such resales of the New Bonds. Terms of the Exchange Offer; Period for Tendering Old Bonds Upon the terms and subject to the conditions set forth in this Prospectus and in the accompanying Letter of Transmittal (which together constitute the Exchange Offer), the Company will accept for exchange Old Bonds which are properly tendered on or prior to the Expiration Date and not withdrawn as permitted below. As used herein, the term "Expiration Date" means 5:00 p.m., New York City time, on September 30, 1997; provided, however, that if the Company, in its sole discretion, has extended the period of time for which the Exchange Offer is open, the term "Expiration Date" means the latest time and date to which the Exchange Offer is extended. As of the date of this Prospectus, $200,000,000 aggregate principal amount of the Old Bonds was outstanding. This Prospectus, together with the Letter of Transmittal, is first being sent to all holders of Old Bonds known to the Company on or about September 2, 1997. The Company's obligation to accept Old Bonds for exchange pursuant to the Exchange Offer is subject to certain conditions as set forth under "-- Certain Conditions to the Exchange Offer" below. The Company expressly reserves the right, at any time or from time to time, to extend the period of time during which the Exchange Offer is open, and thereby delay acceptance for exchange of any Old Bonds, by giving oral or written notice of such extension to the holders thereof. During -21- any such extension, all Old Bonds previously tendered will remain subject to the Exchange Offer and may be accepted for exchange by the Company. Any Old Bonds not accepted for exchange for any reason will be returned without expense to the tendering holder thereof as promptly as practicable after the expiration or termination of the Exchange Offer. Procedures for Tendering Old Bonds The tender to the Company of Old Bonds by a holder thereof as set forth below and acceptance thereof by the Company will constitute a binding agreement between the tendering holder and the Company upon the terms and subject to the conditions set forth in this Prospectus and in the accompanying Letter of Transmittal. Except as set forth below, a holder who wishes to tender Old Bonds for exchange pursuant to the Exchange Offer must transmit a properly completed and duly executed Letter of Transmittal, including all other documents required by such Letter of Transmittal, to Bankers Trust Company (the Exchange Agent), at the address set forth below under "Exchange Agent" on or prior to the Expiration Date. In addition, either (i) certificates for such Old Bonds must be received by the Exchange Agent along with the Letter of Transmittal, or (ii) a timely confirmation of a book-entry transfer (a Book-Entry Confirmation) of such Old Bonds, if such procedure is available, into the Exchange Agent's account at the DTC (the Book-Entry Transfer Facility) pursuant to the procedure for book-entry transfer described below, must be received by the Exchange Agent on or prior to the Expiration Date, or (iii) the holder must comply with the guaranteed delivery procedures described below. THE METHOD OF DELIVERY OF OLD BONDS, LETTERS OF TRANSMITTAL AND ALL OTHER REQUIRED DOCUMENTS IS AT THE ELECTION AND RISK OF THE HOLDERS. INSTEAD OF DELIVERY BY MAIL, IT IS RECOMMENDED THAT HOLDERS USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, SUFFICIENT TIME SHOULD BE ALLOWED TO ASSURE TIMELY DELIVERY. NO LETTERS OF TRANSMITTAL OR OLD BONDS SHOULD BE SENT TO THE COMPANY. Signatures on a Letter of Transmittal or a notice of withdrawal, as the case may be, must be guaranteed unless the Old Bonds surrendered for exchange pursuant thereto are tendered (i) by a registered holder of the Old Bonds who has not completed the box entitled "Special Issuance Instructions" or "Special Delivery Instructions" on the Letter of Transmittal, or (ii) for the account of a registered national securities exchange, a member of the National Association of Securities Dealers, Inc. or a commercial bank or trust company having an officer or correspondent in the United States (collectively, Eligible Institutions.) In the event that signatures on a Letter of Transmittal or a notice of withdrawal, as the case may be, are required to be guaranteed, such guarantees must be by an eligible guarantor institution which is a member of one of the following recognized Medallion Signature Guarantee Programs: the Securities Transfer Agents Medallion Program (STAMP), the New York Stock Exchange Medallion Signature Program (MSP) or the Stock Exchanges Medallion Program (SEMP) (collectively, Eligible Guarantor Institutions). If Old Bonds are registered in the name of a person other than a signer of the Letter of Transmittal, the Old Bonds surrendered for exchange must be endorsed by, or be accompanied by a written instrument or instruments of transfer or exchange, in satisfactory form as determined by the Company in its sole -22- discretion, duly executed by the registered holder with the signature thereon guaranteed by an Eligible Guarantor Institution. All questions as to the validity, form, eligibility (including time of receipt), acceptance and withdrawal of Old Bonds tendered for exchange will be determined by the Company in its sole discretion, which determination shall be final and binding. The Company reserves the absolute right to reject any and all tenders of any particular Old Bonds not properly tendered or to not accept any particular Old Bonds which acceptance might, in the judgment of the Company or its counsel, be unlawful. The Company also reserves the absolute right to waive any defects, irregularities or conditions of the Exchange Offer as to any particular Old Bonds either before or after the Expiration Date (including the right to waive the ineligibility of any holder who seeks to tender Old Bonds in the Exchange Offer). The interpretation of the terms and conditions of the Exchange Offer as to any particular Old Bonds either before or after the Expiration Date (including the Letter of Transmittal and the instructions thereto) by the Company shall be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of Old Bonds for exchange must be cured within such reasonable period of time as the Company shall determine. Neither the Company, the Exchange Agent nor any other person shall be under any duty to give notification of any defect or irregularity with respect to any tender of Old Bonds for exchange, nor shall any of them incur any liability for failure to give such notification. If the Letter of Transmittal is signed by a person or persons other than the registered holder or holders of Old Bonds, such Old Bonds must be endorsed or accompanied by appropriate powers of attorney in either case signed exactly as the name or names of the registered holder or holders appear on the Old Bonds. If the Letter of Transmittal or any Old Bonds or powers of attorney are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in fiduciary or representative capacity, such persons should so indicate when signing and, unless waived by the Company, proper evidence satisfactory to the Company of their authority to so act must be submitted. By tendering, each holder will represent to the Company that, among other things (i) the New Bonds acquired pursuant to the Exchange Offer are being obtained in the ordinary course of business of the person receiving such New Bonds, whether or not such person is the holder, (ii) neither the holder nor any such other person has an arrangement or understanding with any person to participate in the distribution of such New Bonds, and (iii) neither the holder nor any such other person is an "affiliate," as defined under Rule 405 of the Securities Act, of the Company. Each broker-dealer that receives New Bonds for its own account in exchange for Old Bonds will also acknowledge that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of such New Bonds. -23- Acceptance of Old Bonds for Exchange; Delivery of New Bonds Upon satisfaction or waiver of all of the conditions to the Exchange Offer, the Company will accept, promptly after the Expiration Date, all Old Bonds properly tendered and will issue the New Bonds promptly after acceptance of the Old Bonds. See "--Certain Conditions to the Exchange Offer" below. For purposes of the Exchange Offer, the Company shall be deemed to have accepted properly tendered Old Bonds for exchange when as and if the Company has given oral or written notice thereof to the Exchange Agent. In all cases, issuance of New Bonds for Old Bonds that are accepted for exchange pursuant to the Exchange Offer will be made only after timely receipt by the Exchange Agent of certificates for such Old Bonds or a timely Book-Entry Confirmation of such Old Bonds into the Exchange Agent's account at the Book-Entry Transfer Facility, a properly completed and duly executed Letter of Transmittal and all other required documents. If any tendered Old Bonds are not accepted for any reason set forth in the terms and conditions of the Exchange Offer or if Old Bonds are submitted for a greater principal amount than the holder desires to exchange, such unaccepted or non-exchanged Old Bonds will be returned without expense to the tendering holder thereof (or, in the case of Old Bonds tendered by book-entry transfer into the Exchange Agent's account at the Book-Entry Transfer Facility pursuant to the book-entry procedures described below, such non-exchanged Old Bonds will be credited to an account maintained with such Book-Entry Transfer Facility) as promptly as practicable after the expiration or termination of the Exchange Offer. Book-entry Transfer The Exchange Agent will make a request to establish an account with respect to the Old Bonds at the Book-Entry Transfer Facility for purposes of the Exchange Offer within two business days after the date of this Prospectus, and any financial institution that is a participant in the Book-Entry Transfer Facility's systems may make book-entry delivery of Old Bonds by causing the Book-Entry Transfer Facility to transfer such Old Bonds into the Exchange Agent's account at the Book-Entry Transfer Facility in accordance with such Book-Entry Transfer Facility's procedures for transfer. However, although delivery of Old Bonds may be effected through book-entry transfer at the Book-Entry Transfer Facility, the Letter of Transmittal, together with any required signature guarantees and any other required documents, must, in any case, be transmitted to and received by the Exchange Agent at one of the addresses set forth below under "Exchange Agent" on or prior to the Expiration Date or the guaranteed delivery procedures described below must be complied with. Guaranteed Delivery Procedure If a registered holder of the Old Bonds desires to tender such Old Bonds and the Old Bonds are not immediately available, or time will not permit such holder's Old Bonds or other required documents to reach the Exchange Agent before the Expiration Date, or the procedure for book-entry transfer cannot be completed on a timely basis, a tender may be effected if (i) the tender is made through an Eligible Institution, (ii) prior to the Expiration Date, the Exchange Agent received from such Eligible Institution a properly completed and duly executed Letter of Transmittal and Notice -24- of Guaranteed Delivery, substantially in the form provided by the Company (by mail or hand delivery), setting forth the name and address of the holder of Old Bonds, the certificate number or numbers of such Old Bonds and the principal amount of Old Bonds tendered, stating that the tender is being made thereby and guaranteeing that within five business days after the Expiration Date, the certificates for all physically tendered Old Bonds, in proper form for transfer, or a Book-Entry Confirmation, as the case may be, the Letter of Transmittal and any other documents required by the Letter of Transmittal will be deposited by the Eligible Institution with the Exchange Agent, and (iii) the certificates for all physically tendered Old Bonds, in proper form for transfer, or a Book-Entry Confirmation, as the case may be, and all other documents required by the Letter of Transmittal are received by the Exchange Agent within five business days after the Expiration Date. Withdrawal Rights Tenders of Old Bonds may be withdrawn at any time prior to the Expiration Date. For a withdrawal to be effective, a written notice of withdrawal must be received by the Exchange Agent at the address set forth below under "Exchange Agent." Any such notice of withdrawal must specify the name of the person having tendered the Old Bonds to be withdrawn, identify the Old Bonds to be withdrawn (including the principal amount of such Old Bonds), and (where certificates for Old Bonds have been transmitted) specify the name in which such Old Bonds are registered, if different from that of the withdrawing holder. If certificates for Old Bonds have been delivered or otherwise identified to the Exchange Agent, then, prior to the release of such certificates the withdrawing holder must also submit the serial numbers of the particular certificates to be withdrawn and a signed notice of withdrawal and signatures guaranteed by an Eligible Institution unless such holder is an Eligible Institution. If Old Bonds have been tendered pursuant to the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at the Book-Entry Transfer Facility to be credited with the withdrawn Old Bonds and otherwise comply with the procedures of such facility. All questions as to the validity, form and eligibility (including time of receipt) of such notices will be determined by the Company, whose determination shall be final and binding on all parties. Any Old Bonds so withdrawn will be deemed not to have been validly tendered for exchange for purposes of the Exchange Offer. Any Old Bonds which have been tendered for exchange but which are not exchanged for any reason will be returned to the holder thereof without cost to such holder (or, in the case of Old Bonds tendered by book-entry transfer procedures described above, such Old Bonds will be credited to an account maintained at such Book-Entry Transfer Facility for the Old Bonds) as soon as practicable after returned by following one of the procedures described under "--Procedures for Tendering Old Bonds" above at any time on or prior to the Expiration Date. Certain Conditions to the Exchange Offer Notwithstanding any other provision of the Exchange Offer, the Company shall not be required to accept for exchange, or to issue New Bonds in exchange for, any Old Bonds and may terminate or amend the Exchange Offer, at any time prior to the consummation of the Exchange Offer if: (i) the Exchange Offer would violate applicable law or any applicable interpretation of the -25- staff of the Commission, (ii) an action or proceeding is instituted or threatened in any court or by any governmental agency which might materially impair the ability of the Company to proceed with the Exchange Offer or a material adverse development has occurred in any existing action or proceeding with respect to the Company, or (iii) all governmental approvals which the Company deems necessary for the consummation of the Exchange Offer have not been obtained. If the Company determines in its sole discretion that the conditions to the Exchange Offer are not satisfied, the Company may (i) refuse to accept any Old Bonds and return all tendered Old Bonds to the tendering holders, (ii) extend the Exchange Offer and retain all Old Bonds tendered prior to 5:00 p.m. New York City time, on the Expiration Date, subject, however, to the rights of holders to withdraw such Old Bonds (see "--Withdrawal Rights") or (iii) waive such unsatisfied conditions with respect to the Exchange Offer and accept all validly tendered Old Bonds. If such waiver constitutes a material change to the Exchange Offer, the Company will promptly disclose such waiver by means of a prospectus supplement that will be distributed to the registered holders, and the Company will extend the Exchange Offer for a period of five to 10 business days, depending upon the significance of the waiver and the manner of disclosure to the registered holders, if the Exchange Offer would otherwise expire during such five to 10 business day period. Termination of Certain Rights Holders of the Old Bonds to whom this Exchange Offer is made have special rights under the Registration Rights Agreement that will terminate upon the consummation of the Exchange Offer. The Registration Rights Agreement provides that certain rights under such agreement shall terminate upon the occurrence of (i) the filing with the Commission of the Exchange Offer Registration Statement, (ii) the effectiveness under the Securities Act of the Exchange Offer Registration Statement, and (iii) the consummation of the Exchange Offer. Exchange Agent Bankers Trust Company has been appointed as the Exchange Agent for the Exchange Offer. All executed Letters of Transmittal should be directed to the Exchange Agent at the address set forth below. Questions and requests for assistance, requests for additional copies of this Prospectus or of the Letter of Transmittal and requests for Notices of Guaranteed Delivery should be directed to the Exchange Agent addressed as follows: By Overnight Courier By Mail: By Hand Delivery: or Certified Mail: BT Services Tennessee, Inc. Bankers Trust Company BT Services Tennessee, Inc. Reorganization Unit Corporate Trust & Corporate Trust & P.O. Box 292737 Agency Group Agency Group Nashville, TN 37229-2737 Receipt & Delivery Reorganization Unit Window 648 Grassmere Park Road 123 Washington Street, Nashville, TN 37211 1st Floor New York, NY 10006 DELIVERY OF THE LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET FORTH ABOVE DOES NOT CONSTITUTE A VALID DELIVERY. -26- Fees and Expenses The expenses of soliciting tenders will be borne by the Company. The principal solicitation is being made by mail; however, additional solicitation may be made by telegraph, telephone or in person by officers and regular employees of the Company and its affiliates. The Company has not retained any dealer-manager in connection with the Exchange Offer and will not make any payments to brokers, dealers or others soliciting acceptances of the Exchange Offer. The Company, however, will pay the Exchange Agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses in connection therewith. The fees and expenses incident to the Exchange Offer will be paid by the Company. Such expenses include fees and expenses of the Exchange Agent and Trustee, accounting and legal fees and printing costs, among others. Consequences of Failure to Exchange Holders of Old Bonds eligible to participate who do not exchange their Old Bonds for New Bonds pursuant to the Exchange Offer will not have any further registration rights and such Old Bonds will continue to be subject to the restrictions on transfer as set forth in the legend thereon as a consequence of the issuance of the Old Bonds pursuant to exemptions from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Company does not currently anticipate that it will register the Old Bonds under the Securities Act. See "Risk Factors-Consequences of Failure to Exchange." Resales of the New Bonds With respect to resales of New Bonds, based on an interpretation by the staff of the Commission set forth in no-action letters issued to third parties, the Company believes that a holder (other than a person that is an affiliate of the Company within the meaning of Rule 405 under the Securities Act) who exchanges Old Bonds for New Bonds in the ordinary course of business and who is not participating, does not intend to participate, and has no arrangement or understanding with any person to participate, in the distribution of the New Bonds, will be allowed to resell the New Bonds to the public without further registration under the Securities Act and without delivering to the purchasers of the New Bonds a prospectus that satisfies the requirements of Section 10 thereof. However, if any holder acquires New Bonds in the Exchange Offer for the purpose of distributing or participating in a distribution of the New Bonds, such holder cannot rely on the position of the staff of the Commission enunciated in Exxon Capital Holdings Corporation (available May 13, 1988) or similar no-action letters or any similar interpretive letters and must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction, unless an exemption from registration is otherwise available. Further, each broker-dealer that receives New Bonds for its own account in exchange for Old Bonds, where such Old Bonds were acquired by such broker-dealer as a result of market- -27- making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such New Bonds. The Shelf Registration Statement In the event that applicable law or applicable interpretations of the staff of the Commission do not permit the Company to effect the Exchange Offer, or if a holder of the Bonds is not permitted to participate in the Exchange Offer or does not receive freely tradeable New Bonds pursuant to the Exchange Offer or is an affiliate of the Company, the Company will file a Shelf Registration Statement prior to 30 days after such filing obligation arises, relating to all Bonds for which the holders have provided the necessary information. The Company will use its best efforts to have the Shelf Registration Statement declared effective within 150 days after such obligation arises and to keep the Shelf Registration Statement continuously effective until two years after the Issue Date or such shorter period that will terminate when all the registrable Bonds covered by the Shelf Registration Statement have been sold pursuant to the Shelf Registration Statement or otherwise cease being registrable Bonds. The summary herein of the material provisions of the Registration Rights Agreement is believed by the Company to be accurate and complete in all material respects, but is subject to and is qualified in its entirety by reference to, all provisions of the Registration Rights Agreement which provisions are incorporated by reference herein. A copy of the Registration Rights Agreement has been filed with the Commission as an Exhibit to the Registration Statement of which this Prospectus is a part. Accounting Treatment The New Bonds will be recorded at the same carrying value as the Old Bonds, which is face value, as reflected in the Company's accounting records on the date of the exchange. Accordingly, no gain or loss for accounting purposes will be recognized. The expenses of the Exchange Offer and the unamortized expenses related to the issuance of the Old Bonds will be amortized over the term of the New Bonds. -28- The Connecticut Light and Power Company and Subsidiaries SELECTED FINANCIAL DATA/(a)/ (Thousands of Dollars)
For the Six Months a Ended June 30, For the Year Ended December 31, ------------------------- ---------------------------------------------------------------------- 1997 1996 1996 1995 1994 1993 1992 ------------------------- ---------------------------------------------------------------------- (unaudited) Operating Revenues............... $1,199,749 $1,202,354 $2,397,460 $2,387,069 $2,328,052 $2,366,050 $2,316,451 Operating (Loss) Income.......... (10,439) 75,174 29,773 324,026 286,948 241,655 288,088 Net (Loss) Income................ (70,520) 22,151 (80,237) 205,216 198,288 191,449/(b)/ 206,714 Cash Dividends on Common Stock.................. 5,989 103,528 138,608 164,154 159,388 160,365 164,277 At June 30, At December 31, ------------------------- ---------------------------------------------------------------------- 1997 1996 1996 1995 1994 1993 1992 ------------------------- ---------------------------------------------------------------------- (unaudited) Total Assets..................... $6,097,331 $6,134,723 $6,244,036 $6,045,631 $6,217,457 $6,397,405 $5,582,831 Long-Term Debt /(c)/............. 2,044,077 2,038,336 2,038,521 1,822,018 1,823,690 2,057,280 2,087,936 Preferred Stock Not Subject to Mandatory Redemption................... 116,200 116,200 116,200 116,200 166,200 166,200 231,196 Preferred Stock Subject to Mandatory Redemption /(c)/............. 155,000 155,000 155,000 155,000 230,000 230,000 200,000
Obligations Under Capital Leases /(c)/......... 156,990 154,625 155,708 172,264 175,969 177,418 197,404
a) Reclassifications of prior data have been made to conform with the current presentation. b) Includes the cumulative effect of change in accounting for municipal property tax expense, which increased earnings for common shares by $47.7 million. c) Includes portion due within one year. -29- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This following discussion and analysis of the results of operations for the six months ended June 30, 1997 and the three years ended December 31, 1996 contains management's assessment of the Company's financial condition and the principal factors having an impact on the results of operations. This discussion should be read in conjunction with the Company's Consolidated Financial Statements and footnotes appearing elsewhere in this Prospectus. Overview The outages at Millstone have resulted in significantly increased expenditures for replacement power and work undertaken at Millstone, which resulted in a net loss for the Company for the year 1996 and the first six months of 1997. In 1997, while all three units are out of service, the Company expects to continue operating at a loss. The combination of higher expenditures and the uncertainty surrounding when the units will return to service made it necessary to ensure that access to adequate cash levels would be available for the duration of the outages. Management has taken various actions to address NU's nuclear program and liquidity issues; however, these areas continue to be a serious challenge. The Company faces future uncertainty with the rapidly moving trend toward industry restructuring. While restructuring had little direct impact on 1996 or the first six months of 1997 financial results, it creates an environment of significant uncertainty and financial risk for the coming years. As discussed in further detail in "--Restructuring," the financial treatment that strandable investments will be accorded will impact the Company's ability to compete in a restructured environment. The NU Board of Trustees (NU Board) appointed Michael G. Morris as Chairman, President and Chief Executive Officer of NU effective August 19, 1997. Mr. Morris has been elected to comparable positions at most of the subsidiaries of NU, and to Chairman of the Board of Directors of the Company, also effective August 19, 1997. Millstone Outages The Company has an 81 percent joint ownership interest in Millstone 1 and 2 and a 52.93 percent joint ownership interest in Millstone 3. Millstone 1, 2 and 3 have been out of service since November 4, 1995, February 21, 1996 and March 30, 1996, respectively. Subsequent to its January 31, 1996, announcement that Millstone had been placed on its watch list, the NRC has stated that the units cannot return to service until independent, third-party verification teams have reviewed the actions taken to improve the design, configuration and employee concerns issues that prompted the NRC to place the units on its watch list. Upon successful completion of these reviews, the NRC must approve the restart of each unit through a formal commission vote. -30- Management took several key steps toward improving NU's nuclear program during 1996 and will continue to place a high priority on its recovery in 1997. The NU Board formed a committee in April 1996, to provide high-level oversight of the safety and effectiveness of NU's nuclear operations, progress toward resolving open NRC issues and progress in resolving employee, community and customer concerns. In September 1996, Bruce D. Kenyon was appointed President and Chief Executive Officer of Northeast Nuclear Energy Company (NNECO), a wholly-owned subsidiary of NU that operates Millstone, and retired Admiral David M. Goebel was selected to serve as Vice President for Nuclear Oversight. In early 1997, Neil S. Carns was selected to serve as Senior Vice President and Chief Nuclear Officer to oversee Millstone operations. Shortly after his arrival, Mr. Kenyon unveiled a reorganization of NU's nuclear organization that includes executives loaned from unaffiliated utility companies. Millstone 3 has been designated by NU management as the lead unit for restart. Millstone 2 remains on a schedule to be ready for restart shortly after Millstone 3. To provide the resources and focus for Millstone 3, the pace of work on the restart of Millstone 1 was reduced until late in 1997 at which time the full work effort is expected to be resumed. Management believes that Millstone 3 will be ready for restart by the end of the third quarter of 1997, Millstone 2 in the fourth quarter of 1997 and Millstone 1 in the first quarter of 1998. Because of the need for completion of independent inspections and reviews and for the NRC to complete its processes before the NRC Commissioners can vote on permitting a unit to restart, the actual beginning of operations is expected to take several months beyond the time when a unit is declared ready for restart. The NRC's internal schedules at present indicate that a meeting of the Commissioners to act upon a Millstone 3 restart request could occur by mid- December if NU, the independent review teams and NRC staff concur that the unit can return to operation by that time. A similar schedule indicates a mid-March meeting of the Commissioners to act upon a Millstone 2 restart request. Management hopes that Millstone 3 can begin operating by the end of 1997. As management continues to proceed with its current work towards restart, the Independent Corrective Action Verification Program began on May 27, 1997 for Millstone 3 and June 30, 1997 for Millstone 2. The program is expected to end in mid-November 1997 for Millstone 3 and late November 1997 for Millstone 2. The NRC Operational Safety Team Inspection for Millstone 3 is expected to begin in October 1997. Based on a recent review of work efforts and budgets, management believes that the overall 1997 nuclear spending levels, which include both nuclear O&M expenditures and associated support services and capital expenditures, will be slightly higher than previously estimated. The 1997 projected nuclear O&M expenditures are expected to increase, while 1997 projected capital expenditures are expected to decrease. The Company's share of nonfuel O&M costs for Millstone to be expensed in 1997 is now projected to be approximately $353 million compared to $309 million previously estimated. The 1997 projection includes $12 million of restart costs identified to date which are expected to be incurred in 1998 and is net of $50 million of Millstone costs reserved in 1996. The Company's share of 1997 projected capital expenditures for Millstone is expected to -31- decrease from the $48 million previously estimated to $35 million. The Company's share of nonfuel O&M costs for Millstone in 1996 totalled $322 million, including $93 million for incremental costs related to the outages and $50 million reserved for future costs. For the six months ended June 30, 1997, the Company's share of nonfuel O&M costs expensed for Millstone totaled $211 million. The actual expenditures include $40 million reserved for future 1997 restart costs and $12 million reserved for 1998 restart costs, and is net of $50 million of spending against the reserve established in 1996. The reserve balance at June 30, 1997, was approximately $52 million. Nonfuel O&M costs have been and will continue to be absorbed by the Company without adjustment to its current rates. Although 1998 nuclear operating budgets have not been established at this time, management believes that the nuclear spending levels at Millstone will be reduced considerably from 1997 levels, although they will be higher than before the station was placed on the NRC's watch list. The actual level of 1998 spending will depend on when the units return to operation and the cost of restoring them to service. The total cost to restart the units cannot be estimated at this time. Management will continue to evaluate the costs to be incurred for the remainder of 1997 and in 1998 to determine whether adjustments to the existing reserves are required. Replacement power costs for the Company averaged approximately $23 million a month during the first six months of 1997, and are projected to average approximately $21 million a month for the remainder of 1997. Replacement power costs for the Millstone units expensed in 1996 were $216 million, which was a substantial portion of the total 1996 replacement power costs. The Company will continue to expense its replacement power costs in 1997. See "Risk Factors--Nuclear Plant Outages and Liquidity," "- -Rate Matters" and "Business --Overview of Nuclear and Related Financial Matters" and "--Rates" for information relating to the Company's ability to recover these replacement power costs. On July 1, 1997, the Company submitted continued unit operation studies to the DPUC showing that, under base case assumptions, Millstone 1 will have a value to NU system customers (as compared to the cost of shutting down the unit and incurring replacement power costs) of approximately $70 million during the remaining thirteen years of its operating license and Millstone 2 will have a value to NU system customers (on the same assumptions as used with Millstone 1) of approximately $500 million during the remaining eighteen years of its operating license. Two other cases submitted to the DPUC based on higher assumed O&M costs, which the Company considers less likely, indicated that Millstone 1 would be uneconomic in varying degrees. Based on these economic analyses, the Company expects to continue operating both Millstone 1 and Millstone 2 for the remaining terms of their respective operating licenses. The DPUC has stated it will consider these analyses in the context of the Company's next integrated resource planning proceeding which begins in April 1998. As a result of the nuclear situation, a number of civil lawsuits, criminal investigations and regulatory proceedings have been initiated, including litigation by NU's shareholders. On August 7, 1997, the non-NU owners of Millstone 3 filed demands for arbitration with the Company and -32- WMECO as well as lawsuits in Massachusetts Superior Court against NU and its current and former trustees. The NU companies believe there is no legal basis for the claims and intend to defend against them vigorously. To date, no reserves have been established for existing or potential litigation. See "Legal Proceedings" and the notes to the Company's Consolidated Financial Statements, Note 11B, for further information on litigation. Capacity During 1996 and continuing into 1997, the NU system companies have taken measures to improve their capacity position. The Company anticipates spending approximately $56 million for additional capacity-related costs in 1997, of which $38 million is expected to be expensed. The projected 1997 capacity-related expenditures have increased from previous estimates due to additional improvements to existing fossil units and the Company's estimated share of costs to reactivate generating units in New England. In the first six months of 1997, the Company spent approximately $29 million to ensure adequate generating capacity, of which $14 million was expensed. During 1996, the Company spent approximately $60 million of which $42 million was expensed. Despite record-breaking demand in mid-July, the NU system companies has been able to meet capacity requirements without any supply interruptions. Assuming normal weather conditions and generating unit availability, management expects that the Company will have sufficient capacity to meet peak load demands for the remainder of 1997. If there are high levels of unplanned outages at other units in New England, or if any transmission lines used to import power from other states are unavailable, at times of peak load demand, the Company and the other New England utilities may have to resort to operating procedures designed to reduce customer demand. On June 28, 1997, the Seabrook nuclear unit in New Hampshire returned to service following a 50-day planned refueling and maintenance outage. In December 1996, all of the seven power cables installed in the Long Island Sound between the Company's Norwalk Harbor and the Long Island Lighting Company's Northport generating plants were damaged. Repair work has been completed and all cables were back in service by June 26, 1997. The Company has a 12 percent equity ownership interest in Maine Yankee Atomic Power Company (MYAPC), the owner of the Maine Yankee nuclear generating facility (MY). On August 6, 1997, the board of directors of MYAPC voted to permanently close the plant after efforts to sell the nuclear power plant were unsuccessful. MYAPC had previously announced that it was considering permanent closure of the plant based on economic concerns and uncertainty about the operation of the plant. -33- Liquidity and Capital Resources Cash provided from operations decreased approximately $241 million in the first six months of 1997, from 1996 and was a use of funds, primarily due to higher 1997 cash expenditures related to the Millstone outages, and the pay down of the 1996 year end accounts payable balance. The year end accounts payable balance was relatively high due to costs related to a severe December storm and costs associated with the Millstone outages that had been incurred but not yet paid by the end of 1996. Net cash from financing activities increased approximately $43 million, primarily due to an increase in short-term borrowings through the use of the $100 million of the accounts receivable facility established in 1996. Net cash from financing activities was also impacted by lower cash dividends on common shares, partially offset by higher long-term debt retirements. Cash used for investments decreased approximately $197 million, primarily due to lower investments in the Money Pool (defined below). Cash provided from operations decreased by approximately $229 million in 1996 compared to 1995, primarily due to higher cash operating costs related to the Millstone outages and costs associated with ensuring adequate generating capacity, partially offset by higher retail sales and lower income tax payments. Cash flows from operations were also impacted by a sharp increase in the level of accounts payable principally caused by costs related to a severe December 1996 storm and costs associated with the Millstone outages that had not been paid by year end. Net cash used for financing activities decreased by approximately $350 million in 1996, primarily due to higher long-term debt issuances, lower repayment of short- term debt and lower common dividend payments. Cash used for investments increased by approximately $122 million in 1996, primarily due to an increase in investments under the Money Pool. On April 1, 1997, $193 million of the Company's first mortgage bonds matured. The Company funded the maturity with cash available and from long-term debt issuances that took place in 1996 in anticipation of this maturity. The Company established a facility in 1996 under which it may sell up to $200 million of its accounts receivable and accrued utility revenues. As of June 30, 1997, the Company had sold approximately $100 million of its receivables and accrued revenues under this facility. Additionally, the Company, NU, and WMECO entered into a new three-year revolving credit agreement (the New Credit Agreement) in November 1996. On May 30, 1997, the First Amendment and Waiver to the New Credit Agreement became effective. This amendment permits $313.75 million of credit in the aggregate to remain available to the Company and WMECO through the securing of such borrowings with first mortgage bonds. Interest coverage and common equity ratios were revised to enable the companies to meet certain financial tests. The Company will be able to borrow up to $225 million on the strength of bonds it has provided as collateral for borrowings under the revolving credit agreement. WMECO will be able to borrow up to $90 million on the basis of bonds it has provided as collateral. The NU parent company, which as a holding company cannot issue first mortgage bonds, will be able to borrow up to $50 million if the Company, WMECO and -34- NU consolidated financial statements meet certain interest coverage tests for two consecutive quarters. This is not expected to occur until mid-1998. The Company issued the Old Bonds on June 26, 1997. The net proceeds of the sale of the Old Bonds were used for repayment of short-term debt incurred for general working capital purposes, including costs associated with the current outages at the Millstone units. The Company is obligated to offer to exchange publicly tradeable New Bonds for the Old Bonds within 180 days after the issue of the Old Bonds or the interest on the Old Bonds could increase in stages up to a maximum amount of 1.50 percent per annum. In April, 1997, Moody's downgraded most of its ratings of the Company and WMECO securities because of the extended Millstone outages. In May, 1997, S&P also downgraded its ratings of the Company and WMECO securities as a result of the Connecticut legislature failing to approve a utility restructuring bill during the recently completed legislative session. As a result, all NU system securities are currently rated below investment grade by Moody's and S&P. These actions could adversely affect the availability and cost of funds for the NU system companies. On April 17, 1997, the holders of approximately $38 million of notes issued by NU's real estate company (Rocky River Realty Company or RRR) required RRR to repurchase the notes at par. The notes are secured by real estate leases between RRR as lessor and Northeast Utilities Service Company (NUSCO) as lessee. On July 1, 1997, RRR received commitments for the purchase of approximately $12 million of the notes and RRR repurchased the remaining $26 million of notes on July 14, 1997. On July 30, 1997, approximately $6 million of the $12 million were purchased by an alternative purchaser. The remaining $6 million of the notes is expected to be purchased by another purchaser by September 2, 1997. See the notes to the Company's Consolidated Financial Statements, Note 11G for further information. On June 21, 1996, the Company entered into an operating lease with a third party to acquire the use of four turbine generators having an installed cost of approximately $70 million. During the first quarter of 1997, it was determined that the Company would not be in compliance with a financial coverage test required under the lease agreement. The Company has reached an agreement with the lessors for a resolution of this matter. Management believes that the terms and conditions of this agreement will not have a material adverse impact on the Company's financial position or results of operations. Each major company in the NU system finances its own needs. Neither the Company nor WMECO has any agreements containing cross defaults based on events or occurrences involving NU, PSNH or NAEC. Similarly, neither PSNH nor NAEC has any agreements containing cross defaults based on events or occurrences involving NU, the Company or WMECO. Nevertheless, it is possible that investors will take negative operating results or regulatory developments at one company in the NU system into account when evaluating other companies in the NU system. That could, as a practical matter and despite the contractual and legal separations among the NU companies, negatively affect each company's access to the financial markets. -35- If the return to service of one or more of the Millstone units is delayed substantially, or if the needed waivers or modifications discussed above are not forthcoming on reasonable terms, or if some borrowing facilities become unavailable because of difficulties in meeting borrowing conditions, or if the NU system encounters additional significant costs or any other significant deviations from management's current assumptions, the currently available borrowing facilities could be insufficient to meet all of the NU system's cash requirements. In those circumstances, management would take actions to reduce costs and cash outflows and would attempt to take other actions to obtain additional sources of funds. The availability of these funds would be dependent upon the general market conditions and the Company's and the NU system's credit and financial condition at the time. Restructuring The movement toward electric industry restructuring continues to gain momentum nationally as well as within Connecticut. Factors that are driving the move toward restructuring, in the Northeast in particular, include legislative and regulatory actions and relatively high electricity prices. These actions will impact the way that the Company has historically conducted its business. Although the Company continues to operate under cost-of-service based regulation, various restructuring initiatives in Connecticut have created uncertainty with respect to future rates and the recovery of strandable investments. Strandable investments are regulatory assets or other assets that would not be economical in a competitive environment. The Company has exposure to strandable investments for its investment in high-priced nuclear generating plants, state mandated purchased power arrangements that are priced above the market and significant regulatory assets that represent costs deferred by state regulators for future recovery. The Company's exposure to strandable investments and purchased power obligations exceeds its shareholder's equity. The Company's ability to compete in a restructured environment would be negatively affected unless the Company were able to recover substantially all of these past investments and commitments. On June 4, 1997, the Connecticut legislature completed its session without passage of a proposed electric industry restructuring bill. The legislature may consider restructuring legislation in the future. The Company follows accounting principles in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," which allows the economic effects of rate regulation to be reflected. Recently, the Commission has questioned the ability of certain utilities to remain on SFAS No. 71 in light of state legislation regarding the transition to retail competition. The industry expects guidance on this issue from the Financial Accounting Standards Board's Emerging Issues Task Force in the near future. While there are restructuring initiatives pending in Connecticut, the Company is not yet subject to transition plans. -36- If future competition or regulatory actions cause any portion of its operations to no longer be subject to SFAS No. 71, the Company would no longer be able to recognize regulatory assets and liabilities for that portion of its business unless these costs would be recoverable by a portion of the business remaining on cost-of-service based regulation. Under its current regulatory environment, management believes that the Company's use of SFAS No. 71 remains appropriate. If events create uncertainty about the recoverability of any of the Company's remaining long-lived assets, the Company would be required to determine the fair value of its long-lived assets, including regulatory assets, in accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The implementation of SFAS 121 did not have a material impact on the Company's financial position or results of operations as of December 31, 1996. Management believes it is probable that the Company will recover its investments in long-lived assets through future revenues. This conclusion may change in the future as competitive factors influence wholesale and retail pricing in the electric utility industry or if the cost-of-service based regulatory structure were to change. See "Risk Factors--Regulatory Accounting and Assets." Competition In addition to legislative and regulatory actions, competition in the electric utility industry continues to grow at a rapid pace as a result of technological advances; relatively high electricity prices in certain regions of the country, including New England; surplus generating capacity; and the increased availability of natural gas. Competitive forces in the electric utility industry have already caused some customers to choose alternative energy suppliers or relocate outside of the Company's territory. In response, the Company is preparing for a competitive environment by expanding previously established programs and developing new ways to fortify its relationships with existing customers and attract new customers, both within and outside its service territory. The Company has continued to negotiate long-term power supply arrangements with certain large commercial and industrial retail customers that require an incentive to locate or expand their operations within the Company's service territory, are considering leaving or reducing operations in the service territory, are facing short-term financial problems, or are considering generating their own electricity. Approximately 10 percent of the Company's commercial and industrial retail revenues were under negotiated rate agreements at the end of 1996. These negotiated rate reductions amounted to approximately $19 million in 1996 and 1995. These activities are expected to continue in 1997. During 1996, the NU system devoted significantly more resources to its retail marketing organization, whose primary mission is to provide value added energy solutions to customers. Training was emphasized for its 170 new employees, the majority of whom are account executives charged with developing tailored solutions for the NU system's customers and positioning NU as a valuable partner for the future. The ability of these account executives to -37- obtain an intimate understanding of customers' needs and concerns and provide value added energy solutions will play a key role in the NU system's ability to effectively compete in the future. Revenue erosion from traditional retail electric sales may be significant after restructuring. While margins on retail electric sales are likely to be thin, utilities can compete successfully if they are allowed to recover their strandable investments. During 1997 and beyond, the NU system plans to continue to participate in state sanctioned retail access programs; invest in new unregulated businesses; develop new energy-related products and services; and pursue strategic alliances with companies in various energy-related fields, including fuel supply and management, power quality, energy efficiency and load management services. Strategic alliances will allow NU subsidiaries to enter markets that provide access to new product lines and technologies that complement the NU system's current products and services. Rate Matters In July 1996, the DPUC approved a rate settlement agreement with the Company (the Settlement). Under the Settlement, the Company froze base rates until at least December 31, 1997, accelerated the amortization of regulatory assets by $73 million in 1996 and between $54 million and $68 million in 1997, and extended the depreciable lives of transmission and distribution assets by ten years. Additionally, the Settlement terminated all pending litigation, as of March 31, 1996, among the parties that could potentially affect the Company's rates. The Settlement does not impact costs incurred subsequent to March 31, 1996 that are associated with the Millstone outages. The Settlement reduced 1996 earnings by approximately $35 million. The impact on 1997 earnings is not significant. In October 1996, the DPUC issued a final order establishing an Energy Adjustment Clause (EAC), which replaced both the Company's fossil-fuel adjustment clause and its generation utilization adjustment clause (GUAC). The EAC, which is designed to calculate the difference between actual fuel costs and fuel costs collected through base rates, took effect on January 1, 1997. The order includes an incentive mechanism which disallows recovery of the first $9 million of actual fuel costs in excess of base rate levels, but permits the Company to retain the first $9 million in actual fuel costs below base rate levels. In connection with an ongoing management audit of the Company, including matters related to the NRC watch list designation, the two consulting firms hired by the DPUC to review such matters issued reports in December 1996 that were highly critical of NU's management of its nuclear program. The results of these reports may affect future DPUC positions with respect to the NU system's nuclear related operations and costs. On January 15, 1997, the DPUC notified the Company that it would be conducting its prudence review of nuclear cost recovery issues in multiple phases. The first phase, covering the period April 1 through June 30, 1996, was in progress when various intervenors moved for -38- summary judgment with respect to the costs for the entire outage. On June 27, 1997, the DPUC orally granted summary judgment disallowing recovery by the Company of substantially all of its Millstone outage related costs. On July 30, 1997, the DPUC issued a purported "written decision" in the same case disallowing such costs. The Company has not requested cost recovery at this time and has said that it will not seek recovery for a substantial portion of these costs and will not request any cost recovery until the units have returned to operation. Any requests by the Company for recovery would include only costs for projects the Company would have undertaken under normal operating conditions or that provide long-term value for the Company's customers. The Company has appealed the DPUC's decision to the Connecticut Superior Court. The Company has expensed, and continues to expense, the bulk of the Millstone outage costs as they are incurred. Therefore, the Company does not expect this decision to have a material financial impact on projected 1997 results. The DPUC is required to review a utility's rates every four years if there has not been a rate proceeding during such period. On June 16, 1997, the Company filed with the DPUC certain financial information consistent with the DPUC's filing requirements applicable to such four year review. The Company expects hearings before the DPUC to begin soon. The Company cannot predict the outcome of this proceeding. Nuclear Decommissioning The Company has a 34.5 percent equity ownership interest in the Connecticut Yankee nuclear generating facility (CY). On December 4, 1996, the CYAPC Board of Directors voted unanimously to cease permanently the production of power at CY. The decision to retire CY from commercial operation was based on an economic analysis of the costs of operating it compared to the costs of closing it and incurring replacement power costs over the remaining period of CY's operating license, which expires in 2007. The economic analysis showed that closing CY and incurring replacement power costs produced substantial savings. CYAPC has undertaken a number of regulatory filings intended to implement the decommissioning. In late December 1996, CYAPC filed an amendment to its power contracts with the Federal Energy Regulatory Commission (FERC) to clarify the obligations of its purchasing utilities following the decision to cease power production. At December 31, 1996, the Company's share of these obligations was approximately $263 million, including the cost of decommissioning and the recovery of existing assets. Management expects that the Company will continue to be allowed to recover such FERC-approved costs from its customers. Accordingly, the Company has recognized its share of the estimated costs as a regulatory asset, with a corresponding obligation, on its balance sheets. The Company's estimated cost to decommission its shares of Millstone 1, 2 and 3 and Seabrook is approximately $858 million in year end 1996 dollars. These costs are being recognized over the lives of the respective units with a portion being currently recovered through rates. As of December 31, 1996, the market value of the contributions already made to the decommissioning trusts, including their investment returns, was approximately $297 million. -39- On August 6, 1997, the board of directors of MYAPC voted unanimously to cease permanently the production of power at MY. MYAPC has begun to prepare the regulatory filings intended to implement the decommissioning and the recovery of remaining assets of MYAPC. During the latter part of 1997, MYAPC plans to file an amendment to its power contracts to clarify the obligations of its purchasing utilities following the decision to cease power production. MYAPC is currently updating its decommissioning cost estimates. These estimates are expected to be completed during the third quarter of 1997. At this time, the Company is unable to estimate its obligation to MYAPC. Under the terms of the contracts with MYAPC, the shareholders-sponsor companies, including the Company, are responsible for their proportionate share of the costs of the unit, including decommissioning. Management expects that the Company will be allowed to recover these costs from its customers. See the notes to the Company's Consolidated Financial Statements, Note 3, for further information on nuclear decommissioning, including the Company's share of costs to decommission the regional nuclear generating units. Environmental Matters The Company is potentially liable for environmental cleanup costs at a number of sites inside and outside its service territory. To date, the future estimated environmental remediation liability has not been material with respect to the earnings or financial position of the Company. For the period ended June 30, 1997, the Company had recorded an environmental reserve of approximately $8 million, the most probable amount as required by SFAS No. 5, "Accounting for Contingencies." See the notes to the Company's Consolidated Financial Statements, Note 11C, for further information on environmental matters. Risk Management Instruments The Company uses fuel price management instruments to reduce a portion of the fuel price risk associated with certain of its long-term negotiated energy contracts and replacement-power expense during the Millstone outages. The Company's fuel price management instruments seek to minimize exposure associated with rising fuel prices and effectively fix the cost of fuel and maintain the profitability of certain of its long-term negotiated contract sales. These instruments are not used for trading purposes. The differential paid or received as fuel prices change is recognized in income when realized. As of June 30,1997, the Company had outstanding fuel price management instruments with a total notional value of approximately $318 million. The settlement amounts for the -40- second quarter of 1997 associated with the instruments decreased fuel expense by approximately $0.8 million. Since March 31, 1997, the Company has entered into additional fuel price management agreements with a total notional value of approximately $75 million. As of December 31, 1996, the Company had outstanding fuel-price management instruments with a total notional value of approximately $229 million. The settlement amounts associated with the instruments reduced fuel expense by approximately $7.5 million for the Company during 1996. The Company's fuel-price management instruments seek to minimize exposure associated with rising fuel prices and effectively fix the cost of fuel and profitability of certain of its long-term negotiated contract sales. For further information on risk management instruments, see the notes to the Company's Consolidated Financial Statements, Note 12. Results Of Operation Comparison of the First Six Months of 1997 to the First Six Months of 1996 The Company had a net loss of approximately $64 million in the second quarter of 1997 compared to a net loss of approximately $11 million in the second quarter of 1996, and a net loss of approximately $71 million for the six months ended June 30, 1997, compared to net income of approximately $22 million for the same period in 1996. The losses for the three-and six-month periods were primarily attributable to replacement-power and nuclear O&M expenses for the Millstone units in 1997 including amounts reserved for future spending. The loss for the first six months of 1997 was also attributable to lower retail sales. Retail kilowatt-hour sales for the first half of 1997 were 1.9 percent below the same period in 1996 primarily due to mild weather in the first quarter of 1997. Total operating revenues decreased in 1997, primarily due to lower retail sales ($16 million), lower wholesale revenues ($11 million), lower fuel recoveries ($8 million), partially offset by higher revenues from regulatory decisions ($14 million) and higher transmission and other revenues ($9 million). Wholesale revenues decreased primarily due to lower 1997 capacity sales. Retail sales decreased 1.9 percent primarily due to mild weather in the first quarter of 1997. Revenues from regulatory decisions increased primarily due to higher recoveries of demand-side- management costs. Fuel, purchased and net interchange power expense increased in 1997, primarily due to higher replacement-power costs expensed in 1997 due to the nuclear outages. Other operation expense decreased $31 million and maintenance expense increased $36 million in 1997. The major factors were the higher costs associated with the Millstone outages ($60 million) and higher capacity charges from MY ($7 million); partially offset by lower recognition of nuclear refueling outage costs as a result of the Rate Settlement ($34 million); lower 1997 administrative and general expenses primarily due to lower pensions and benefit costs ($15 million) and lower capacity charges from purchased power ($9 million). -41- Amortization of regulatory assets, net increased in 1997, primarily due to the higher amortization of cogeneration deferrals in 1997 ($23 million) and higher amortizations as a result of the Rate Settlement ($9 million). These were partially offset by the completion of the amortization of phase-in costs for Seabrook ($6 million). Federal and state income taxes decreased in 1997, primarily due to lower book taxable income. Interest charges increased in 1997, primarily due to higher 1997 average long-term debt levels and interest expense associated with the sale of the accounts receivable. Comparison of 1996 to 1995 The Company had a net loss of approximately $80 million in 1996, compared to net income of approximately $205 million in 1995. The 1996 loss was primarily due to costs related to the ongoing outages at Millstone which totaled approximately $400 million and reduced the Company's 1996 earnings by approximately $232 million. These costs included replacement power, higher 1996 Millstone O&M costs, a reserve recognized in 1996 for 1997 expenditures to return the Millstone units to service and costs associated with ensuring adequate generating capacity. In addition, 1996 earnings decreased due to the impact of the Company's approved rate settlement agreement, higher recognition of cogeneration costs and higher nonnuclear O&M costs. These decreases were partially offset by higher retail sales and lower recognition of Millstone 3 phase-in costs. Total operating revenues increased in 1996, primarily due to higher retail sales and regulatory decisions, partially offset by lower fuel recoveries and lower wholesale revenues. Retail sales increased 1.8 percent ($29 million) primarily due to modest economic growth in 1996. Regulatory decisions increased revenues by $15 million primarily due to the mid-1995 retail rate increase, partially offset by 1996 reserves for over-recoveries of demand side management costs. Fuel recoveries decreased $24 million primarily due to lower average fossil fuel prices. Wholesale revenues decreased $18 million primarily due to higher recognition in 1995 of lump- sum payments for the termination of a long-term contract and capacity sales contracts that expired in 1995. Fuel, purchased and net interchange power expense increased in 1996, primarily due to replacement power due to the nuclear outages and the 1996 write-off of GUAC balances under the Settlement, partially offset by lower nuclear generation and the timing of the recognition of costs under the Company's fuel clauses. Other O&M expenses increased in 1996, primarily due to higher costs associated with the Millstone outages ($143 million, including $50 million reserved for future costs) and 1996 costs to ensure adequate generating capacity ($39 million). In addition, these costs reflect higher -42- storm and reliability expenditures, higher recognition of conservation expenses and higher marketing costs. Higher plant balances and higher decommissioning levels in 1996 were partially offset by longer depreciable lives of transmission and distribution assets under the Settlement. Amortization of regulatory assets, net increased in 1996, primarily due to lower cogeneration deferrals and the accelerated amortization of regulatory assets as a result of the Settlement, partially offset by the completion of the Millstone 3 phase-in amortization in 1995. Federal and state income taxes decreased in 1996, primarily due to lower book taxable income, partially offset by 1995 tax benefits from a favorable tax ruling. Although the change in 1996 was not significant, deferred nuclear plants return decreased in 1995, primarily due to the completion of the Millstone 3 phase-in in 1995. Other, net increased in 1996, primarily due to higher income on temporary cash investments in 1996. Comparison of 1995 to 1994 Total operating revenues increased in 1995, primarily due to regulatory decisions and higher fuel recoveries, partially offset by lower retail sales and wholesale revenues. Revenues related to regulatory decisions increased $61 million primarily due to the effects of the mid- 1994 and 1995 retail rate increases and higher recoveries for demand side management costs. Fuel and purchased power cost recoveries increased $25 million primarily due to higher energy costs and the recovery of GUAC costs. Wholesale revenues decreased $16 million primarily due to capacity sales contracts that expired in 1994. Fuel, purchased and net interchange power expense increased in 1995, primarily due to higher fossil generation and higher priced outside energy purchases from other utilities. Other O&M expenses increased in 1995, primarily due to higher recognition of conservation expense, higher recognition of post-retirement benefit costs and higher capacity charges from the regional nuclear generating units, partially offset by higher reserves for excess/obsolete inventory in 1994 and lower maintenance costs at the fossil units. Depreciation increased in 1995, primarily due to higher plant balances and higher decommissioning levels. Amortization of regulatory assets, net decreased in 1995, primarily due to higher cogeneration deferrals in 1995 and the completion during 1994 of the amortization of a 1993 -43- cogeneration buyout, partially offset by higher 1995 amortization of Millstone 3 and Seabrook 1 phase-in costs. Federal and state income taxes decreased in 1995, primarily due to tax benefits from a favorable tax ruling, partially offset by higher book taxable income. Other, net decreased in 1995, primarily due to the 1993 property tax accounting change as ordered in the 1993 rate decision. The allocation of this change to customers occurred in 1994 and amortization began in 1995. Minority interest in income of subsidiary increased in 1995, primarily due to the issuance of Monthly Income Preferred Securities in 1995. BUSINESS Overview of Nuclear and Related Financial Matters On January 29, 1996, Millstone was placed on the NRC's watch list as a Category 2 facility. As set forth below, the Company has significant financial and capacity interests in Millstone. Facilities in Category 2 have been identified by the NRC as having weaknesses that warrant increased attention until the licensee, NNECO, demonstrates a period of improved performance. Millstone was subsequently reclassified as a Category 3 facility, which requires NNECO to receive formal NRC Commissioners' approval to restart any of the units. Millstone 1, 2 and 3 have been out of service since November 4, 1995, February 21, 1996 and March 30, 1996, respectively. Following these decisions, the NU system faced in 1996, and continues to face, some of the most severe regulatory scrutiny and financial challenges in the history of the United States nuclear industry, including numerous civil lawsuits and criminal investigations and regulatory proceedings. See "Risk Factors--Nuclear Plant Outages and Liquidity" and "Legal Proceedings." Millstone 1, a 660-MW boiling water reactor, and Millstone 2, an 870- MW pressurized water reactor, are each jointly owned 81 percent by the Company and 19 percent by WMECO. Millstone 3, a 1,154-MW pressurized water reactor, is jointly owned by the Company (52.93 percent), WMECO (12.24 percent), PSNH (2.85 percent) and other New England utilities. The NU system companies have initiated a number of changes in the management of the NU system's nuclear program to address the problems at Millstone. In April 1996, the NU Board announced the formation of a special committee of the NU Board to provide high-level oversight of the safety and effectiveness of NU's nuclear operations and the progress toward resolving open NRC issues and employee, community and customer concerns. The committee consists exclusively of outside trustees. It is chaired by E. Gail de Planque, who is a former NRC Commissioner. In light of substantial NU Board activities associated with the current nuclear situation, the NU Board elected Elizabeth T. Kennan in 1996 as Lead Trustee to facilitate the extensive ongoing communications and activities between the NU Board and management. In addition, on June 17, -44- 1997, the shareholders elected William F. Conway, a nuclear power industry consultant, and former executive with several power companies, to the NU Board . In response to various internal reports and other reviews that focused on nuclear management as a fundamental cause for the decline in the performance of Millstone, the NU Board elected Bruce D. Kenyon as President--Nuclear Group of NU, in September 1996. Following this appointment, management unveiled a reorganization of NU senior nuclear management at each of the nuclear power units that the NU system operates. The new management team, including executives loaned from unaffiliated utility companies with excellent nuclear programs, has focused in the near- term on the recovery efforts of Millstone and improving nuclear oversight and the NU system's employee concerns program. In January 1997, Neil S. Carns was elected to the position of Senior Vice President and Chief Nuclear Officer of NNECO to oversee the operations of Millstone. Both Mr. Kenyon and Mr. Carns have extensive experience at other utilities with reputations for excellent nuclear operation. The new nuclear management team has developed comprehensive plans for restarting each of the Millstone units. The Company currently anticipates that Millstone 3 will be ready for restart by the end of the third quarter of 1997, Millstone 2 in the fourth quarter of 1997 and Millstone 1 in the first quarter of 1998. Because of the need for completion of independent inspections and reviews and for the NRC to complete its processes before the NRC Commissioners can vote on permitting a unit to restart, the actual beginning of operations is expected to take several months beyond the time when a unit is declared ready for restart. The NRC's internal schedules at present indicate that a meeting of the Commissioners to act upon a Millstone 3 restart request could occur by mid-December if NU, the independent review teams and NRC staff concur that the unit can return to operation by that time. A similar schedule indicates a mid-March meeting of the Commissioners to act upon a Millstone 2 restart request. Management hopes that Millstone 3 can begin operating by the end of 1997. There can be no assurances, however, that the Company's expectations will be met. Before and following notification to the NRC that a unit is ready to resume operations, management expects that the NRC staff will conduct extensive reviews and inspections, and before such notification, independent corrective action verification teams also will inspect each unit. The NU system also will need to comply with an NRC order regarding the development of a comprehensive employee concerns program, which will need to be reviewed by an independent third party. Furthermore, because of the length of the outages, management cannot estimate the time it will take for the units to resume full power after NRC approval to restart. For more information regarding specific regulatory actions related to NU's nuclear units and the December 4, 1996 decision of the board of directors of Connecticut Yankee Atomic Power Company (CYAPC) to retire CY from commercial operation, see "--Electric Operations--Nuclear Generation." For information regarding actions taken to meet NU system capacity needs caused by the Millstone outages, see "--Electric Operations--Distribution and Load." -45- As a result of the extended Millstone outages, the NU system companies have incurred and will continue to bear substantial costs at least until the three Millstone units have been restarted. Most of the costs are being borne by the Company and WMECO, which have the greatest investment share of the Millstone units. In 1996, the Company expensed a total of approximately $322 million for Millstone-related non-fuel O&M costs, which included among other costs $93 million for non-fuel incremental O&M costs related to the Millstone outages and $50 million reserved for future Millstone incremental O&M costs. Based on a recent review of work efforts and budgets, management believes that the overall 1997 nuclear spending levels for both projected nuclear O&M expenditures and associated support services and projected capital expenditures will be slightly higher than previously estimated. 1997 projected nuclear O&M expenditures and related support services are expected to increase, while 1997 projected capital expenditures are expected to decrease. For further information concerning estimated 1997 spending levels, see "Management's Discussion and Analysis of Financial Condition and Results of Operations," and notes to the Company's Consolidated Financial Statements, Notes 11B and 11E. The Company also expensed approximately $216 million for replacement power costs in 1996. Management cannot predict when the NRC will allow any of the Millstone units to return to service and thus cannot estimate the total replacement power costs the Company will ultimately incur. Replacement power costs incurred by the Company attributable to the Millstone outages averaged approximately $23 million per month during the first six months of 1997, and are projected to average approximately $21 million per month for the remainder of 1997. The Company expensed a significant portion of its 1996 replacement power costs related to the nuclear outages and it is continuing to expense 1997 replacement power costs. Based on current estimates of expenditures and restart dates, management believes the NU system has sufficient resources to fund the restoration of the Millstone units and related replacement power costs. Management has committed not to seek recovery of the portion of these costs attributable to the failure to meet industry standards in operating Millstone. In light of that commitment, management has said that the Company will not seek recovery of a substantial portion of such costs. While the Company believes that it is entitled to recovery of a portion of the costs that have been and will be incurred, and intends to apply for recovery of such costs, the DPUC on June 27, 1997 orally granted summary judgment in a prudence proceeding disallowing recovery by the Company of most of its Millstone outage related costs. On July 30, 1997, the DPUC issued a purported "written decision" in the same case, which disallowed recovery of an estimated $600 million of replacement power costs related to the Millstone outages, and found that the Company had waived recovery of an additional $360 million of incremental O&M. The written decision, like the oral decision, recognized the Company's right to seek recovery, in a future rate proceeding, of $40 million related to reliability enhancements. The Company has appealed the DPUC's decision. Management currently does not intend to request any such cost recoveries until after the Millstone units begin returning to service, so it is unlikely that any additional revenues from any permitted recovery of these costs will be available while the units are out of service to contribute to funding the recovery efforts. Any requests for recovery would include only costs for projects the Company -46- would have undertaken under normal operating conditions or that provide long-term value for the Company's customers. The Company has arranged a variety of borrowing facilities to fund its cash requirements, including the nuclear recovery efforts. See "--Financing Program--1997 Financing Requirements." The length of the Millstone outages and the high costs of the recovery efforts weakened the Company's 1996 earnings, balance sheet and cash flows, and they continue to have a significant negative impact on the Company's earnings. The Company had a net loss of approximately $70 million in the first half of 1997. In 1997, while all three units are out of service the Company expects to continue operating at a loss. Management believes that the borrowing facilities that are currently in place provide the Company with adequate access to the funds needed to bring the Millstone units back to service if those units begin operating close to the currently envisioned schedules and if the other assumptions, on which management has based its planning, do not substantially change. If the return to service of one or more Millstone units is delayed substantially, or if any needed waivers or modifications to the Company's financing arrangements are not forthcoming on reasonable terms, or if the Company encounters additional significant costs or other significant deviations from management's current assumptions, the currently available borrowing facilities could be insufficient to meet all of the Company's cash requirements, and some facilities could become unavailable because of difficulties in meeting borrowing conditions. In those circumstances, management would take actions to reduce costs and cash outflows and would attempt to take actions to arrange additional sources of funds. The availability of such sources would be dependent on general market conditions and the Company's and the NU system's credit and financial condition at the time. Both Moody's and S&P have recently downgraded the Company's senior debt to Ba1 and BB+, respectively. Electric Operations Distribution and Load The NU system companies own and operate a fully integrated electric utility business. The Company's retail electric service territory covers approximately 4,400 square miles and has an estimated total population of approximately 2.5 million. The Company furnishes retail electric franchise service in 149 cities and towns in Connecticut. In December 1996 the Company furnished retail electric franchise service to approximately 1.1 million customers. The following table shows the sources of the Company's 1996 electric revenues based on categories of customers: -47-
Residential........................ 42% Commercial......................... 35 Industrial......................... 13 Wholesale*......................... 8 Other.............................. 2 --- Total.............................. 100%
* Includes capacity sales Through December 31, 1996, the all-time peak demand on the NU system was 6,358 MW, which occurred on August 2, 1995. At the time of the peak, the NU system's generating capacity, including capacity purchases, was 8,035 MW. NU system energy requirements were met in 1996 and 1995 as set forth below:
Source 1996 1995 ------- ----- ----- Nuclear.......... 28% 52% Oil.............. 12 4 Coal............. 11 10 Hydroelectric.... 5 3 Natural gas...... 3 5 NUGs............. 13 13 Purchased-power.. 28 13 ---- ---- 100% 100%
The actual changes in retail KWh sales for the last two years and the forecasted sales growth estimates for the ten-year period 1996 through 2006, in each case exclusive of wholesale revenues, for the Company are set forth below:
1996 compared to 1995 compared to Forecast 1996-2006 1995 1994 Compound Rate of Growth - ------------------ ----------------- ------------------------ 1.8% (.3)% 1.1%
Retail electric sales for the Company rose by 1.8 percent in 1996 compared to 1995, primarily due to moderate growth in the residential and commercial classes, which increased by 2.0 and 2.9 percent, respectively, in 1996. Industrial sales decreased by 1.0 percent in 1996. Weather has had a minimal effect on 1996 growth rates because the increase in winter heating requirements due to abnormally cold winter weather was offset by the decrease in summer cooling requirements due to a relatively cool summer. In spite of further defense and insurance curtailments, moderate growth is forecasted to resume over the next ten years. The forecasted annual growth rate for the Company of one percent -48- is significantly below historic rates due to a general slow down of economic growth in the region and, in part, because of forecasted savings from Company-sponsored DSM programs that are designed to minimize operating expenses for Company customers and reduce their demand for electricity. The forecasted ten-year annual growth rate of the Company sales would be approximately 1.7 percent if the Company did not pursue DSM programs at the forecasted levels. See "--Rates" for information about rate treatment of DSM costs. The Company also acts as both a buyer and a seller of electricity in the highly competitive wholesale electricity market in the Northeastern United States (Northeast). The Company's revenues from long-term contracts were $188 million in 1995 and $177 million in 1996, and are expected to be at approximately the same level in 1997. The Company's most important wholesale market at this time remains New England. With the NU system's generating capacity of 8,034 MW (which includes the Millstone units) as of January 1, 1997 (including the net of capacity sales to and purchases from other utilities, and approximately 660 MW of capacity purchased from NUGs under existing contracts), the NU system expects to meet reliably its projected annual peak load growth of 1.6 percent until at least the year 2010 without adding new capacity. The NU system companies operate and dispatch their generation as provided in the New England Power Pool (NEPOOL) Agreement (as defined below). In 1996, the peak demand on the NEPOOL system was 19,507 MW in August, which was 992 MW below the 1995 peak load of 20,499 MW in July of that year. NEPOOL has projected that there will be an increase in demand in 1997 and estimates that the summer 1997 peak load could reach 21,390 MW. Management expects that the NU system and NEPOOL will have sufficient capacity to meet peak load demands for New England even if Millstone and the 300 MW Long Island Cable are not operational at any time during the 1997 summer season, so long as the remaining generating units and transmission systems in Connecticut and the New England region have normal operability. If high levels of unplanned outages in New England were to occur, or if any of the NU system's transmission lines used to import power from other states were unavailable at times of peak load demand, NU and the other New England utilities may have to resort to operating procedures designed to reduce load. The Company spent approximately $60 million in 1996 to reduce the risk of unplanned outages and expects to spend approximately $55 million in 1997. Most of the money budgeted for 1997 will be used to improve the NU system's network of transmission lines to increase imports into Connecticut and for lease payments for additional capacity. Regional and System Coordination The NU system companies and most other New England utilities are parties to an agreement (NEPOOL Agreement), which coordinates the planning and operation of the region's generation and transmission facilities. NU system transmission lines form part of the New England transmission system linking NU system generating plants with one another and with the facilities of other utilities in the Northeast and Canada. The generating facilities of all NEPOOL participants are dispatched -49- as a single system through the New England Power Exchange, a central dispatch facility. The NEPOOL Agreement provides for a determination of the generating capacity responsibilities of participants and certain transmission rights and responsibilities. NEPOOL's objectives are to assure that the bulk power supply of New England and adjoining areas conforms to proper standards of reliability, to attain maximum practical economy in the bulk power supply system consistent with such reliability standards and to provide for equitable sharing of the resulting benefits and costs. Pursuant to the NEPOOL Agreement, if a participant is unable to meet its capacity responsibility obligations, the participant is required to pay NEPOOL a deficiency charge based on the cost of a proxy generating unit . In the event that none of the Millstone units is returned to service by November 1, 1997, the NU system companies could be required to begin paying this deficiency charge under the NEPOOL Agreement. Management, however, expects to meet its capacity responsibility obligations even if the Millstone units do not return to service as currently scheduled through purchased power contracts with other utilities and/or reactivating NU system fossil generating units and thus avoid the deficiency charge. The costs of these alternative plans cannot be estimated at this time. A restated and revised NEPOOL Agreement, providing for pool-wide open access transmission tariff and a proposal for the creation of an Independent System Operator (ISO), became effective on March 1, 1997. Under these new arrangements (1) the ISO, a non-profit corporation, whose board of directors and staff will not be controlled by or affiliated with market participants, will ensure the reliability of the NEPOOL transmission system, administer the NEPOOL tariff and oversee the efficient and competitive functioning of the regional power market, (2) the NEPOOL tariff will provide for non-discriminatory open access to the regional transmission network at one rate regardless of transmitting distance for all transactions, and (3) the new NEPOOL Agreement will establish a broader governance structure for NEPOOL and develop a more open, competitive market structure. There are two agreements that determine the manner in which costs and savings are allocated among the NU system companies. Under an agreement among the Company, WMECO and HWP (Initial System Companies), such parties pool their electric production costs and the costs of their principal transmission facilities (NUG&T). Pursuant to the merger agreement between NU and PSNH, the Initial System Companies and PSNH entered into a ten-year sharing agreement (Sharing Agreement), expiring in June 2002, that provides, among other things, for the allocation of the capability responsibility savings and energy expense savings resulting from a single- system dispatch through NEPOOL. Transmission Access and FERC Regulatory Changes On April 24, 1996, FERC issued its final open access rule (the Rule) to promote competition in the electric industry. As required by the Rule, all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce must file an open access, non-discriminatory transmission tariff and take transmission service for their own new wholesale sales and purchases under the open access tariffs. The Rule also requires public utilities to develop and -50- maintain a same-time information system that will give existing and potential transmission users the same access to transmission information that the public utility enjoys, and requires public utilities to separate transmission from generation marketing functions and communications. The Rule also supports full recovery of legitimate, prudent and verifiable wholesale strandable investments. On February 26, 1997, FERC reaffirmed the Rule with a few minor clarifications. On July 8, 1996, NU refiled its transmission tariffs to conform with the minimum terms and conditions set forth in the Rule. On December 31, 1996, NU filed amendments to its transmission tariff and several other compliance filings to meet the Rule's year-end requirements, including standards of conduct ensuring that transmission and wholesale generation personnel function independently. As of January 3, 1997, NU operates pursuant to the requirements of the standards of conduct and participates in a NEPOOL-wide Open Access Same-Time Information System, which provides transmission customers with electronic access to information on available capacity, tariffs and other information. On January 22, 1997, NU refiled its transmission tariff to account for certain transmission services that would be provided by NEPOOL under the new NEPOOL Agreement (discussed above), which was filed on December 31, 1996. In 1996, the Company collected approximately $30 million in incremental transmission revenues from other electric utility generators. Fossil Fuels In 1996, 12 percent and 11 percent of the NU system's generation was oil and coal-derived, respectively. The Company's residual oil-fired generation stations used approximately 5.8 million barrels of oil in 1996. The Company obtained the majority of its oil requirements in 1996 through contracts with several large, independent oil companies. Those contracts allow for some spot purchases when market conditions warrant. Spot purchases represented approximately 15 percent of the Company's fuel oil purchases in 1996. The contracts expire annually or biennially. The Company currently does not anticipate any difficulties in obtaining necessary fuel oil supplies on economic terms. The Company has four generating stations, aggregating approximately 2,060 MW, which can fully or partially burn either residual oil or natural gas, as economics, environmental concerns or other factors dictate. In addition, the Company has converted two of the four units at its oil-fired Middletown Station in Connecticut comprising approximately 350 MW of capacity to a dual-fuel generating facility. The Company has contracts with the local gas distribution companies where the dual-fuel generating units are located, under which natural gas is made available by those companies on an interruptible basis. In addition, gas for the Company's Devon and Montville generating stations is being purchased directly from producers and brokers on an interruptible basis and transported through the interstate pipeline system and the local gas distribution company. The Company expects that interruptible natural gas will continue to be available for its dual-fuel electric generating units on economic terms and will continue to economically supplement fuel oil requirements. -51- Nuclear Generation General Certain NU system companies have joint ownership interests in four operating nuclear units, Millstone 1, 2 and 3 and Seabrook 1, and equity interests in four regional nuclear companies (the Yankee Companies) that separately own CY, MY, Vermont Yankee (VY) and the Yankee Rowe nuclear generating facility (Yankee Rowe). NU system companies operate the three Millstone units and Seabrook 1. Yankee Rowe was permanently removed from service in 1992, CY was permanently removed from service on December 4, 1996 and MY was permanently removed from service on August 6, 1997. The NU system companies will have responsibility for administering the decommissioning of CY. The Company and WMECO own 100 percent of Millstone 1 and 2 as tenants in common. Their respective ownership interests in each unit are 81 percent and 19 percent. The Company, PSNH and WMECO have agreements with other New England utilities covering their joint ownership as tenants in common of Millstone 3. The Company's ownership interest in the unit is 52.93 percent, PSNH's ownership interest in the unit is 2.85 percent and WMECO's interest is 12.24 percent. NAEC and the Company have 35.98 percent and 4.06 percent ownership interests, respectively, in Seabrook. The Millstone 3 and Seabrook joint ownership agreements provide for pro-rata sharing by the owners of each unit of the construction and operating costs, the electrical output and the associated transmission costs. The Company and WMECO, through NNECO as agent, operate Millstone 3 at cost, and without profit, under a sharing agreement that obligates them to utilize good utility operating practice and requires the joint owners to share the risk of employee negligence and other risks pro rata in accordance with their ownership shares. The sharing agreement provides that the Company and WMECO would only be liable for damages to the non-NU owners for a deliberate breach of the agreement pursuant to authorized corporate action. The Company, PSNH, WMECO and other New England electric utilities are the stockholders of the Yankee Companies. Each Yankee Company owns a single nuclear generating unit. The stockholder-sponsors of each Yankee Company are responsible for proportional shares of the operating costs of the respective Yankee company and are entitled to proportional shares of the electrical output. The relative rights and obligations with respect to the Yankee Companies are approximately proportional to the stockholders' percentage stock holdings, but vary slightly to reflect arrangements under which nonstockholder electric utilities have contractual rights to some of the output of particular units. The Yankee Companies and the Company's, PSNH's and WMECO's stock ownership percentages in the Yankee Companies are set forth below: -52-
CL&P PSNH WMECO NU system ----- ---- ----- --------- Connecticut Yankee Atomic Power Company (CYAPC)...................... 34.5% 5.0% 9.5% 49.0% Maine Yankee Atomic Power Company.................................... 12.0% 5.0% 3.0% 20.0% Vermont Yankee Nuclear Power Corporation (VYNPC).................. 9.5% 4.0% 2.5% 16.0% Yankee Atomic Electric Company (YAEC)............................. 24.5% 7.0% 7.0% 38.5%
The Company is obligated to provide its percentage of any additional equity capital necessary for the Yankee Companies, but does not expect to need to contribute additional equity capital in the future. The Company believes that VY could require additional external financing in the next several years to finance construction expenditures, nuclear fuel and for other purposes. Although the ways in which VYNPC would attempt to finance these expenditures, if they are needed, have not been determined, the Company could be asked to provide further direct or indirect financial support for these companies. The operators of Millstone 1, 2 and 3, MY, VY and Seabrook 1 hold full power operating licenses from the NRC. As holders of licenses to operate nuclear reactors, the Company, WMECO, North Atlantic Energy Service Corporation (NAESCO), NNECO and the Yankee Companies are subject to the jurisdiction of the NRC. The NRC has broad jurisdiction over the design, construction and operation of nuclear generating stations, including matters of public health and safety, financial qualifications, antitrust considerations and environmental impact. The NRC issues 40-year initial operating licenses to nuclear units and NRC regulations permit renewal of licenses for an additional 20-year period. The NRC also regularly conducts generic reviews of technical and other issues, a number of which may affect the nuclear plants in which NU system companies have interests. The cost of complying with any new requirements that may result from these reviews cannot be estimated at this time, but such costs could be substantial. For information regarding recent actions taken by the NRC with respect to the NU system's nuclear units, see "--Overview of Nuclear and Related Financial Matters" and "-- Nuclear Generation--Nuclear Plant Performance and Regulatory Oversight." -53- Nuclear Plant Performance and Regulatory Oversight Millstone Units Millstone 1, 2 and 3 are located in Waterford, Connecticut and have license expirations of October 6, 2010, July 31, 2015 and November 25, 2025, respectively and are currently out of service. These units are presently on the NRC's watch list as Category 3 plants, the lowest such category. Plants in this category are required to receive formal NRC Commissioners' approval to resume operations. Millstone 1 began a planned refueling and maintenance outage on November 4, 1995. Millstone 2 was shut down on February 21, 1996 as a result of an engineering evaluation that determined that some valves could be inoperable in certain emergency scenarios. On March 30, 1996, Millstone 3 was shut down by NNECO following an engineering evaluation which determined that four safety-related valves would not be able to perform their design function during certain postulated events. Each of these outages has been extended in order to respond to various NRC requests to describe actions taken, including the resolution of specific technical issues, and to ensure that future operation of the units will be conducted in accordance with the terms and conditions of their operating licenses, NRC regulations and their Updated Final Safety Analysis Report. The NU system also must demonstrate that it maintains an effective corrective action program for Millstone, as required by NRC regulations, to identify and resolve conditions that are adverse to safety or quality. For more information regarding nuclear management changes and costs related to the outages, see "--Overview of Nuclear Matters and Related Financial Matters." Based upon management's current plans, it is estimated that Millstone 3 will be ready for restart by the end of the third quarter of 1997, Millstone 2 in the fourth quarter of 1997, and Millstone 1 in the first quarter of 1998. Prior to and following notification to the NRC that the units are ready to resume operations, management expects that the NRC staff will conduct extensive reviews and inspections, and prior to such notification, independent corrective action verification teams (as discussed more fully below) also will inspect each unit. The NU system also will need to comply with an NRC order regarding the implementation of a comprehensive employee concerns program, which will need to be reviewed by an independent third party (as discussed more fully below). The units will not be allowed to restart without an affirmative vote of the NRC Commissioners following completion of these reviews and inspections. Because of the need for completion of independent inspections and reviews and for the NRC to complete its processes before the NRC Commissioners can vote on permitting a unit to restart, the actual beginning of operations is expected to take several months beyond the time when a unit is declared ready for restart. The NRC Commissioners' vote on a Millstone 3 restart request could occur by mid-December if NU, the independent review teams and NRC staff concur that the unit can return to operation by that time. Management hopes that Millstone 3 can begin operating by the end of 1997. Because of the length of the outages, however, management cannot estimate the time it will take for the units to resume full power after NRC approval to restart. -54- On August 14, 1996, the NRC issued an order confirming NNECO's agreement to conduct an Independent Corrective Action Verification Program (ICAVP) prior to the restart of each of the Millstone units. The order requires that an independent, third-party team, whose appointment is subject to NRC approval, verify the results of the corrective actions taken to resolve identified design and configuration management issues. NNECO has submitted to the NRC its selection of an ICAVP contractor for each of the units and the NRC has approved those selections. The ICAVP for Millstone 3 began on May 27, 1997, as scheduled. On June 30, 1997, the Company announced that Millstone 2 was ready to begin the ICAVP, as scheduled, and requested that the NRC identify the particular systems to be reviewed by the Millstone 2 ICAVP contractor. The ICAVP is expected to end in mid-November 1997 for Millstone 3 and late November 1997 for Millstone 2. The NRC Operational Safety Team Inspection for Millstone 3 is expected to begin in October 1997. In the fall of 1996, the NRC established a Special Projects Office to oversee inspection and licensing activities at Millstone. The Special Projects Office is responsible for (1) licensing and inspection activities at Millstone, (2) oversight of the independent corrective action verification program, (3) oversight of NU's corrective actions related to safety issues involving employee concerns, and (4) inspections necessary to implement NRC oversight of the plants' restart activities. On December 5, 1996, the NRC conducted an enforcement conference regarding numerous apparent regulatory violations at Millstone that were discovered during routine and special inspections at the units between November 1995 and November 1996. It is likely that this proceeding will result in the issuance of notices of violation and the imposition of significant civil penalties for each of the Millstone units. In addition to the various technical and design basis issues at Millstone, the NRC continues to focus on the NU system's response to employee concerns at the units. On October 24, 1996, the NRC issued an order that requires NNECO to devise and implement a comprehensive plan for handling safety concerns raised by Millstone employees and for assuring an environment free from retaliation and discrimination. The NRC also ordered NNECO to contract for an independent third party to oversee this comprehensive plan. The members of the independent third-party organization must not have had any direct previous involvement with activities at Millstone and must be approved by the NRC. Oversight by the third-party group will continue until NNECO demonstrates, by performance, that the conditions leading to this order have been corrected. NNECO has submitted to the NRC its selection of the third-party oversight organization and the NRC has approved that selection. NNECO has submitted to the NRC its comprehensive employee concerns plan. On March 7, 1997, the NRC issued a letter to NNECO confirming NNECO's commitment to evaluate and correct problems identified within its licensed operator training programs at Millstone and CY. On June 27, 1997, NNECO temporarily suspended all nuclear training programs at Millstone to address programmatic deficiencies identified by NNECO and NRC inspectors during reviews of the NU system's licensed operator training programs at Millstone and CY. Since then, a Training Restart Plan has been established and various training programs have been restarted, including the licensed operator training programs for Millstone. Management continues to believe -55- that the suspension will not affect the schedule to restart the Millstone units See "Legal Proceedings--NRC Office of Investigations and U.S. Attorney Investigations and Related Matters." Nuclear management is investigating the cause of a temperature rise in the Millstone 3 spent fuel pool that occurred during the last week of June 1997. Preliminary analysis indicates that the cause of the event was an incomplete changeover from one cooling system to another. Nuclear management does not believe that this incident, when considered in isolation, presented a significant safety issue, but is taking steps to prevent it from recurring and identify lessons to be learned from the event. The NRC has been informed of the event but is not expected to impose any material sanctions on the Company. However, the event has indicated to nuclear management that further focus on operational matters will be necessary to ensure proper operation of the units. For information regarding replacement power costs and incremental nuclear O&M costs associated with the extended Millstone outages, see "Risk Factors--Nuclear Plant Outages and Liquidity" and "--Overview of Nuclear and Related Financial Matters." For information regarding the recoverability of these costs, see "--Rates." For information regarding the 1996 nuclear workforce reduction, see "Employees." For information regarding criminal investigations by the NRC's Office of Investigations (OI) and the Office of the U.S. Attorney for the District of Connecticut related to various matters at Millstone and CY; certain citizens petitions related to NU's nuclear operations; and joint owner litigation related to the extended outages, see "Legal Proceedings." Seabrook Seabrook 1, a 1,148-MW pressurized-water reactor, has a license expiration date of October 17, 2026. The Seabrook operating license expires 40 years from the date of issuance of authorization to load fuel, which was about three and one-half years before Seabrook's full-power operating license was issued. The NU system will determine at the appropriate time whether to seek recapture of some or all of this period from the NRC and thus add up to an additional three and one-half years to the operating term for Seabrook. In 1996, Seabrook operated at a capacity factor of 96.5 percent. On June 28, 1997, the unit completed a planned refueling and maintenance outage that lasted 50 days. On October 9, 1996, the NRC issued a request for information concerning all nuclear plants in the United States, except the three Millstone units and CY, which had previously received such requests. Such information will be used to verify that these facilities are being operated and maintained in accordance with NRC regulations and the unit's specific licenses. The NRC has indicated that the information will be used to determine whether future inspection or enforcement activities are warranted for any plant. NAESCO has submitted its response to the NRC's request with respect to Seabrook. Seabrook's operations have not been restricted by the request. The NRC's April 1996 comprehensive review found Seabrook to be a well-operated facility without any major safety issues or weaknesses and noted that it would reduce its future inspections in a number of areas as a result of its findings. -56- Yankee Units Connecticut Yankee. CY, a 582-MW pressurized-water reactor, has a license expiration date of June 29, 2007. On July 22, 1996, CY began an unscheduled outage as a precautionary measure to evaluate the plant's service water system, which provides cooling water to certain critical plant components. On August 8, 1996, after evaluating certain other pending technical and regulatory issues, CY's management decided to delay the restart of the unit and to begin a scheduled September refueling outage. The refueling outage was accelerated in order to allow time to resolve the pending issues. On December 4, 1996, the board of directors of CYAPC voted unanimously to retire CY. The decision to shut down CY was based on economic analyses that showed that shutting down the unit prematurely and incurring replacement power costs could produce potential savings compared to the costs of operating it over the remaining period of the unit's operating license. These analyses indicated that this shutdown decision could produce savings in excess of $130 million on a net present value basis. These analyses did not consider the costs of addressing concerns about CY's design and licensing basis raised by the NRC during the summer of 1996 similar to those raised at Millstone. If these costs had been considered, the economic analyses would have favored shutdown by an even greater margin. CYAPC has undertaken a number of regulatory filings intended to implement the decommissioning. For more information regarding the CYAPC revised decommissioning estimate that was submitted to FERC in December 1996, see "--Decommissioning." In late December 1996, CY filed amendments to its power contracts with FERC to clarify any obligations of its purchasing utilities, including the Company. This filing estimated the unrecovered obligations, including the funding of decommissioning, to be approximately $762.8 million. On February 27, 1997, FERC approved an order for hearing which, among other things, accepted CY's contract amendments for filing and suspended the new rates for a nominal period. The new rates became effective March 1, 1997, subject to a refund. At June 30, 1997, the Company's share of the CY unrecovered contractual obligation which also has been recorded as a regulatory asset, was approximately $235 million. Based upon FERC regulatory precedent, CYAPC believes it will be allowed to continue to collect from its power purchasers, including the Company, WMECO and PSNH, CYAPC's decommissioning costs, the owners' unrecovered investments in CYAPC, and other costs associated with the permanent closure of the plant over the remaining period of its NRC operating license. Management in turn expects that the Company, WMECO and PSNH will continue to be allowed to recover such FERC-approved costs from their customers. On May 12, 1997 the NRC staff assessed a $650,000 fine against CYAPC for more than 70 alleged violations of regulatory requirements, which CYAPC paid on June 13, 1997. Most of the violations cited by the NRC pertain to numerous longstanding deficiencies in engineering programs and practices, as well as errors related to an event involving a nitrogen buildup in the reactor vessel in 1996. -57- As confirmed by the NRC on March 4, 1997, CYAPC has agreed to undertake various steps to resolve deficiencies and weaknesses in the radiation protection program at CY. Management does not believe that this undertaking will have a material adverse effect on the NU system companies or CYAPC. Maine Yankee. The Company has a twelve percent equity ownership interest in MYAPC. At June 30, 1997, the Company's equity investment in MYAPC was approximately $8.9 million. The NU system companies had relied on MY for approximately two percent of their capacity. On August 6, 1997, the board of directors of MYAPC voted unanimously to cease permanently the production of power at MY. MYAPC has begun to prepare the regulatory filings intended to implement the decommissioning and the recovery of remaining assets of MYAPC. During the latter part of 1997, MYAPC plans to file an amendment to its power contracts to clarify the obligations of its purchasing utilities following the decision to cease power production. MYAPC is currently updating its decommissioning cost estimates. These estimates are expected to be completed during the third quarter of 1997. At this time, the Company is unable to estimate its obligation to MYAPC. Under the terms of the contracts with MYAPC, the shareholders-sponsor companies, including the Company, are responsible for their proportionate share of the costs of the unit, including decommissioning. Management expects that the Company will be allowed to recover these costs from its customers. Vermont Yankee. VY, a 514-MW boiling water reactor, has a license expiration date of March 21, 2012. In 1996, VY operated at a capacity factor of 81.4 percent. VY had a 57-day planned refueling outage during 1996 that ended on November 1, 1996. The unit expects to begin a 56-day planned refueling and maintenance outage on September 28, 1998. Yankee Rowe. In 1992, YAEC's owners voted to shut down Yankee Rowe permanently based on an economic evaluation of the cost of a proposed safety review, the reduced demand for electricity in New England, the price of alternative energy sources and uncertainty about certain regulatory requirements. The power contracts between the Company, PSNH, WMECO, and other owners and YAEC permit YAEC to recover from each its proportional share of the Yankee Rowe shutdown and decommissioning costs. For more information regarding the decommissioning of Yankee Rowe, see "-- Decommissioning." Nuclear Insurance The NRC requires nuclear plant licensees to maintain a minimum of $1.06 billion in nuclear property and decontamination insurance coverage. The NRC requires that proceeds from the policy following an accident that exceed $100 million will first be applied to pay expenses. The insurance carried by the licensees of the Millstone units, Seabrook 1, CY, MY and VY meets the NRC's requirements. YAEC has obtained an exemption for Yankee Rowe from the $1.06 billion requirement and currently carries $25 million of insurance that otherwise meets the requirements of the rule. CYAPC expects to seek a similar exemption for CY in 1997. For more information regarding nuclear insurance, see "Commitments and Contingencies--Nuclear Insurance Contingencies" in the notes to the Company's Consolidated Financial Statements, Note 11D. -58- Nuclear Fuel The supply of nuclear fuel for the NU system's existing units requires the procurement of uranium concentrates, followed by the conversion, enrichment and fabrication of the uranium into fuel assemblies suitable for use in the NU system's units. The majority of the NU system companies' uranium enrichment services requirements is provided under a long-term contract with the United States Enrichment Corporation (USEC), a wholly-owned United States government corporation. The majority of Seabrook's uranium enrichment services requirements is furnished through a Russian trading company. The NU system expects that uranium concentrates and related services for the units operated by the NU system and for the other units in which the NU system companies are participating, that are not covered by existing contracts, will be available for the foreseeable future on reasonable terms and prices. In August 1995, NAESCO filed a complaint in the United States Court of Federal Claims challenging the propriety of the prices charged by the USEC for uranium enrichment services procured for Seabrook Station in 1993. The complaint is an appeal of the final decision rendered by the USEC contracting officer denying NAESCO's claims, which range from $2.5 to $5.8 million, and will likely be considered along with similar complaints that are pending before the court on behalf of 13 other utilities. The NAESCO complaint has been suspended pending the outcome of an appeal in another proceeding involving a similar complaint. As a result of the Energy Act, the United States commercial nuclear power industry is required to pay the United States Department of Energy (DOE), through a special assessment for the costs of the decontamination and decommissioning of uranium enrichment plants owned by the United States government, no more than $150 million per annum for 15 years beginning in 1993. Each domestic nuclear utility's payment is based on its pro rata share of all enrichment services received by the United States commercial nuclear power industry from the United States government through October 1992. Each year, the DOE adjusts the annual assessment using the Consumer Price Index. The Energy Act provides that the assessments are to be treated as reasonable and necessary current costs of fuel, which costs shall be fully recoverable in rates in all jurisdictions. The Company's total share of the estimated assessment was approximately $49.3 million at June 30, 1997 and approximately $49.2 million at December 31, 1996. Management believes that the DOE assessments against the Company will be recoverable in future rates. Accordingly, the Company has recognized these costs as a regulatory asset, with a corresponding obligation on its consolidated balance sheet. In June 1995, the United States Court of Federal Claims held that, as applied to YAEC, the Uranium Enrichment Decontamination and Decommissioning Fund is an unlawful add-on to the bargained-for contract price for enriched uranium. As a result of that ruling, the federal government would be required to refund the approximately $3.0 million that YAEC has paid into the fund since its inception. On May 6, 1997, the United States Court of Appeals for the Federal Circuit issued a 2-1 panel decision reversing the Court of Federal Claims' decision. YAEC has filed a motion for rehearing en banc with the Appeals Court. NU is evaluating the applicability of these decisions to -59- the $21 million that the NU system companies have already paid into the fund for the NU system companies' obligation to pay such special assessments in the future. Nuclear fuel costs associated with nuclear plant operations include amounts for disposal of nuclear waste. The NU system companies include in their nuclear fuel expense spent fuel disposal costs accepted by the DPUC, NHPUC and DPU in rate case or fuel adjustment decisions. Spent fuel disposal costs also are reflected in FERC-approved wholesale charges. High-Level Radioactive Waste The Nuclear Waste Policy Act of 1982 (NWPA) provides that the federal government is responsible for the permanent disposal of spent nuclear reactor fuel and high-level waste. As required by the NWPA, electric utilities generating spent nuclear fuel (SNF) and high-level waste are obligated to pay fees into a fund which would be used to cover the cost of siting, constructing, developing and operating a permanent disposal facility for this waste. The NU system companies have been paying for such services for fuel burned starting in April 1983 on a quarterly basis since July 1983. The DPUC, NHPUC and DPU permit the fee to be recovered through rates. In return for payment of the fees prescribed by the NWPA, the federal government is to take title to and dispose of the utilities' high- level wastes and spent nuclear fuel. The NWPA provides that a disposal facility be operational and for the DOE to accept nuclear waste for permanent disposal in 1998. On March 3, 1997 CYAPCO, NAESCO and NUSCO intervened as parties in a lawsuit brought in the U.S. Court of Appeals for the District of Columbia Circuit by 35 nuclear utilities in late January, seeking additional action based on the DOE's assertion that it expects to be unable to begin acceptance of spent nuclear fuel for disposal by January 31, 1998. Among other requests for relief, the lawsuit requests that utilities be relieved of their contractual obligation with DOE to pay fees into the Nuclear Waste Fund and be authorized to place such fee payments into escrow "unless and until" DOE begins accepting spent fuel for disposal. The DOE's current estimate for an available site is 2010. Until the federal government begins accepting nuclear waste for disposal, operating nuclear generating plants will need to retain high- level waste and spent fuel onsite or make some other provisions for their storage. With the addition of new storage racks, storage facilities for Millstone 3 are expected to be adequate for the projected life of the unit. With the implementation of currently planned modifications, the storage facilities for Millstone 1 and 2 are expected to be adequate (maintaining the capacity to accommodate a full-core discharge from the reactor) until 2003 and 2004, respectively. Fuel consolidation, which has been licensed for Millstone 2, could provide adequate storage capability for the accommodation of all of the SNF at CY. In addition, other licensed technologies, such as dry storage casks or on-site transfers, are being considered to accommodate spent fuel storage requirements. With the current installation of new racks in its existing spent fuel pool, Seabrook is expected to have spent fuel storage capacity until at least 2010. The storage capacity of the spent fuel pool at VY is expected to be reached in 2005 and the available capacity of the pool is expected to be able to accommodate full-core removal until 2001. -60- Because the Yankee Rowe plant was permanently shut down in February 1992, YAEC is considering the construction of a temporary facility to store the spent nuclear fuel produced by the Yankee Rowe plant over its operating lifetime until that fuel is removed by the DOE. Low-Level Radioactive Waste The NU system currently has contracts to dispose its low-level radioactive waste (LLRW) at two privately operated facilities in Clive, Utah and in Barnwell, South Carolina. Because access to LLRW disposal may be lost at any time, the NU system has plans that will allow for onsite storage of LLRW for at least five years. Neither Connecticut nor New Hampshire has developed alternatives to out-of- state disposal of LLRW to date. Both Maine and Vermont are in the process of implementing an agreement with Texas to provide access to an LLRW disposal facility that is to be developed in that state. All three states plan to form an LLRW compact that is currently awaiting approval by Congress. Decommissioning Based upon the NU system's most recent comprehensive site- specific updates of the decommissioning costs for each of the three Millstone units and for Seabrook, the recommended decommissioning method continues to be immediate and complete dismantlement of those units at their retirement. The table below sets forth the estimated Millstone and Seabrook decommissioning costs for the Company. The estimates are based on the latest site studies, escalated to June 30, 1997 dollars.
(Millions) Millstone 1 $ 428.2 Millstone 2 324.6 Millstone 3 282.0 Seabrook 18.8 -------- Total $1,053.6
As of June 30, 1997, the Company recorded balances (at market) in its external decommissioning trust funds as follows:
(Millions) Millstone 1 $151.9 Millstone 2 100.3 Millstone 3 68.3 Seabrook 2.5 ------ Total $323.0
-61- In 1986, the DPUC approved the establishment of separate external trusts for the currently tax-deductible portions of decommissioning expense accruals for Millstone 1 and 2 and for all expense accruals for Millstone 3. The DPUC has authorized the Company to collect its current decommissioning estimate for the three Millstone units from customers. This estimate includes an approximate 16 percent contingency factor for the decommissioning cost of each unit. The decommissioning cost estimates for the Company's nuclear units are reviewed and updated regularly to reflect inflation and changes in decommissioning requirements and technology. Changes in requirements or technology, or adoption of a decommissioning method other than immediate dismantlement, could change these estimates. The Company attempts to recover sufficient amounts through its allowed rates to cover its expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by the DPUC and FERC is reflected in rates of the Company. Based on present estimates, and assuming its nuclear units operate to the end of their respective license periods, the Company expects that the decommissioning trust funds will be substantially funded when those expenditures have to be made. CYAPC, YAEC, VYNPC and MYAPC are all collecting revenues for decommissioning from their power purchasers. The table below sets forth the Company's estimated share of decommissioning costs of the Yankee units. The estimates are based on the latest site studies, escalated to December 31, 1996 dollars. For information on the equity ownership of the NU system companies in each of the Yankee units, see "--Electric Operations--Nuclear Generation--General."
(Millions) VYNPC $ 34.8 YAEC* 42.5 CYAPC* 263.2 MYAPC **
* As discussed more fully below, the costs shown include all remaining decommissioning costs and other closing costs associated with the early retirement of Yankee Rowe and CY as of December 31, 1996. See "--Electric Operations--Nuclear Generation-- Yankee Units--Maine Yankee." The Company expects to recover all decommissioning costs from its customers pursuant to FERC tariffs. ** MYAPC is currently updating its decommissioning cost estimates. These estimates are expected to be completed during the third quarter of 1997. At this time, the Company is unable to estimate its obligation to MYAPC. -62- As of June 30, 1997, the Company's share of the respective external decommissioning trust fund balances (at market), which have been recorded on the books of each of the respective Yankee Companies, is as follows:
(Millions) VYNPC $ 16.6 YAEC 31.3 CYAPC 73.9
MYAPC 22.0 ------ Total $143.8
Effective January 1996, YAEC began billing its sponsors, including the Company, WMECO and PSNH, amounts based on a revised estimate approved by the FERC that assumes decommissioning by the year 2000. This revised estimate was based on continued access to the Barnwell, South Carolina, low-level radioactive waste facility, changes in assumptions about earnings on decommissioning trust investments, and changes in other decommissioning cost assumptions. CYAPC accrues decommissioning costs on the basis of immediate dismantlement at retirement. In late December 1996, CYAPC made a filing with FERC to amend the wholesale power contracts between the owners of the facility, and revise decommissioning cost estimates and other cost estimates for the facility. The amendments clarify the owners' entitlement to full recovery of amounts previously invested and the ongoing costs of maintaining the plant in accordance with NRC rules until decommissioning begins, and ensures that decommissioning will continue to be funded through June 2007, the full license term, despite the unit's early shutdown. On February 26, 1997, FERC approved a draft order setting for hearing the prudence of the decision to close CY. On February 27, 1997, FERC approved an order for hearing which, among other things, accepted CYAPC's contract amendments for filing and suspended the new rates for a nominal period. The new rates became effective March 1, 1997, subject to refund. FERC will determine the prudence of CYAPC's decision to retire the plant before it finally determines the justness and reasonableness of CYAPC's proposed amended power contract rates. For more information regarding nuclear decommissioning, see "Nuclear Decommissioning" in the notes to the Company's Consolidated Financial Statements, Note 3. Competition and Cost Recovery Competition in the energy industry continues to grow as a result of legislative and regulatory action, technological advances, relatively high electric rates in certain regions of the country, including New England, surplus generating capacity and the increased availability of natural gas. These competitive pressures are particularly strong in the NU system's service territories, where legislators and regulatory agencies have been at the forefront of the restructuring movement. -63- A major risk of competition for the Company is "strandable investments." These are expenditures that have been made by utilities in the past to meet their public service obligations, with the expectation that they would be recovered from customers in the future. However, under certain circumstances these costs might not be recoverable from customers in a fully competitive electric utility industry. The Company is particularly vulnerable to strandable investments because of (i) the Company's relatively high investment in nuclear generating capacity, which had a high initial cost to build, (ii) state-mandated purchased power arrangements priced above market, and (iii) significant regulatory assets, which are those costs that have been deferred by state regulators for future collection from customers. See "Risk Factors--Industry Restructuring and Competition." As of June 30, 1997, the Company's net investment in nuclear generating capacity, excluding its investment in certain regional nuclear companies, was approximately $2.3 billion, and in its regulatory assets was approximately $1.2 billion. The Company expects to recover substantially all of its nuclear investment and its regulatory assets from customers. The Company is currently collecting its nuclear investment through depreciation charges approved by the DPUC. See "Depreciation" in the notes to the Company's Consolidated Financial Statements. Unless amortization levels are changed from currently scheduled rates, the Company's regulatory assets are expected to be substantially decreased in the next five years. Although the Company continues to operate predominantly in a state-approved franchise territory under traditional cost-of-service regulation, restructuring initiatives in the State of Connecticut have created uncertainty with respect to future rates and the recovery of strandable investments. See "Risk Factors--Regulatory Accounting and Assets." In 1995 regulators in Connecticut concluded that electric utilities should be allowed a reasonable opportunity to recover strandable investments. Various electric utility restructuring legislative proposals were introduced in the Connecticut legislature in 1997. On June 4, 1997, the Connecticut legislature completed its most recent session without passage of a proposed electric restructuring bill. The legislature may consider restructuring legislation in the future. Notwithstanding these legislative and regulatory initiatives, the NU system has developed, and is continuing to develop, a number of marketing initiatives to retain and continue to serve its existing customers. In particular, the NU system has been devoting increasing attention in recent years to negotiating long-term power supply arrangements with certain large commercial and industrial retail customers. Approximately 10 percent of the Company's commercial and industrial retail revenues were under negotiated rate agreements at the end of 1996. The Company was a party to negotiated rate agreements which accounted for approximately $19 million of rate reductions in 1996. The average term of these agreements is approximately 5.2 years. The NU system has expanded its retail marketing organization to provide value-added solutions to its customers. The NU system devoted significantly more resources to its retail marketing efforts in 1996 than in prior years. In particular, NUSCO hired approximately 170 new employees as part of its retail sales organization. The new employees will allow the NU system to have more direct contact with customers in order to develop tailor-made solutions for customers' energy needs. In addition, the NU system companies, as well as other NU subsidiaries, received -64- orders from the Commission and FERC in 1996 that increased their flexibility to market and broker electricity, gas, oil and other forms of energy throughout the United States and to provide various services related thereto. Rates General The Company's retail rates are subject to the jurisdiction of the DPUC. Connecticut law provides that revised rates may not be put into effect without the prior approval of the DPUC. Connecticut law also authorizes the DPUC to order a rate reduction under certain circumstances before holding a full-scale rate proceeding. The DPUC is further required to review a utility's rates every four years if there has not been a rate proceeding during such period. On June 16, 1997, the Company filed with the DPUC certain financial information consistent with the DPUC's filing requirements applicable to such four year review. The Company expects hearings before the DPUC with respect to such review to begin during the summer of 1997. Based on recently enacted legislation, if the DPUC approves performance-based incentives for a particular company, the DPUC will include in such an order periodic monitoring and review of the Company's performance in lieu of the four-year review. On July 1, 1996, the DPUC approved a settlement agreement (Settlement) that had been jointly submitted to the DPUC by the Company, the Connecticut Office of Consumer Counsel (OCC) and the independent Prosecutorial Division of the DPUC. The Settlement provides that the Company's base rates will be frozen until at least December 31, 1997. The Settlement provides that during the rate freeze, the Company's target return on equity (ROE) will be 10.7 percent, but the Settlement does not alter Company's allowed ROE of 11.7 percent. One-third of earnings above the target ROE will be refunded to customers. The Settlement also accelerated the amortization of the Company's regulatory assets ($73 million in 1996 and $54 to $68 million in 1997). As of June 30, 1997, the Company's regulatory assets totaled approximately $1.2 billion. The Settlement terminated all outstanding litigation pending as of March 31, 1996 among the parties that potentially could affect the Company's rates. Such litigation included appeals by the Company and the OCC from the Company's 1993 rate case decision, appeals from the DPUC's decisions concerning the 1992-1993 and 1993-1994 fuel-recovery periods, nuclear operating prudence review proceedings pending at the time of the settlement, and OCC's appeal from the DPUC guidelines adopted in 1995 allowing additional flexibility in negotiating special rates with electric customers. In exchange, the Company agreed not to seek recovery from its customers of approximately $115 million in uncollected nuclear costs incurred before March 31, 1996. The Settlement does not affect issues to be addressed by the DPUC in future restructuring proceedings and the recovery of costs related to the ongoing Millstone outages. For information regarding the prudence proceeding related to nuclear operations for the period March 31, 1996 to June 30, 1996. See "--Rates--CL&P Adjustment Clauses and Prudence." -65- Electric Industry Restructuring in Connecticut Pursuant to legislation introduced in 1995, a legislative task force was created to consider electric industry restructuring in Connecticut. Although the members of the task force did not come to a consensus on restructuring, the task force's December 1996 report included several recommendations on legislation, including, among other things, legislation to enable securitization of strandable investments; reduction of tax burdens incorporated in electric rates; reduction of rate impacts of government-mandated contracts with NUGs; and elimination of obsolete regulation. On June 4, 1997, the Connecticut legislature completed its most recent session without passage of a proposed electric industry restructuring bill. The legislature may consider restructuring legislation in the future. CL&P Adjustment Clauses and Prudence On October 8, 1996, the DPUC issued its final order establishing an EAC in place of the Company's existing Fuel Adjustment Clause and GUAC. The EAC took effect on January 1, 1997. The EAC is designed to reconcile and adjust every six months the difference between actual fuel costs and the fuel revenue collected through base rates. The EAC includes an incentive mechanism that disallows recovery of the first $9 million in fuel costs that exceeds base levels and permits the Company to retain the first $9 million in fuel cost savings. The EAC also designates a 60 percent nuclear capacity factor floor. When the six-month nuclear capacity factor falls below 60 percent, related energy costs are deferred to the subsequent EAC period for consideration for recovery. Finally, the costs to serve nonfirm wholesale transactions will continue to be removed from the calculation of fuel costs at actual marginal cost. On December 31, 1996, the DPUC issued a decision approving the Company's request to recover $25 million, excluding replacement power costs (see below), through the GUAC for the period April 1-July 31, 1996. The $25 million will be recovered over a twelve-month period beginning January 1, 1997. On June 6, 1997, the Company filed with the DPUC a request to recover approximately $28 million of fuel costs for the period August 1, 1996 through April 30, 1997, through the EAC, which includes $5.3 million of fuel costs from 1996, which would have been recovered through the GUAC. Pursuant to a DPUC order in the prudence proceeding discussed below, the filing excluded any fuel cost associated with the current outages at Millstone. On the same date, the DPUC issued a procedural order, which stated that the Company could not include CY replacement power costs in its EAC until the DPUC concluded its prudence investigation, discussed more fully below, and that this prudence decision would be directly affected by the on-going FERC proceeding regarding the decision to retire CY before the expiration of its operating license. In response to the June 6, 1997 DPUC order, the Company revised its EAC filing on June 13, 1997 to identify approximately $17 million of replacement power costs incurred by the Company as a result of the retirement of CY on December 4, 1996 . On July 17, 1997, the Company filed an appeal of the June 6th DPUC order. The Company takes the position that unless and until there is a determination that such post-retirement costs are unreasonable, it is entitled to current recovery. See "--Nuclear Plant Performance and Regulatory Oversight--Yankee Units--Connecticut Yankee" and "--Decommissioning." -66- In connection with an ongoing management audit of the Company, including matters related to the NRC watch list designation, the two consulting firms hired by the DPUC to review such matters issued reports in December 1996 that were highly critical of NU's management of its nuclear program. The results of these reports may affect future DPUC positions with respect to the NU system's nuclear-related operations and costs. Despite an earlier procedural order indicating that prudence hearings on the current nuclear outages at Millstone would take place after the nuclear plants return to service, on January 15, 1997, the DPUC notified the Company that it would be conducting its prudence review of nuclear cost recovery issues in multiple phases. The first phase, covering the period April 1 through June 30, 1996, was in progress when various intervenors moved for summary judgment with respect to the costs for the entire outage. On June 27, 1997, the DPUC orally granted summary judgment in the prudence docket, disallowing recovery of substantially costs associated with the ongoing outages at Millstone. The Company has projected that its share of the total costs for the Millstone outages, including replacement power, operation and maintenance and capacity reliability projects, will be about $990 million. The Company has not requested cost recovery at this time and has said that it will not seek recovery for a substantial portion of these costs and will not request any cost recovery until the units had returned to operation. Any requests by the Company for recovery would include only costs for projects the Company would have undertaken under normal operating conditions or that provide long-term value for the Company's customers. On July 30, 1997, the DPUC issued a purported "written decision" in the same case, which disallowed recovery of an estimated $600 million of replacement power costs related to the Millstone outages, and found that the Company had waived recovery of an additional $360 million of incremental O&M. The written decision, like the oral decision, recognized the Company's right to seek recovery, in a future rate proceeding, of $40 million related to reliability enhancements. The Company has appealed the DPUC's decision. Management currently does not intend to request any such cost recoveries until after the Millstone units begin returning to service, so it is unlikely that any additional revenues from any permitted recovery of these costs will be available while the units are out of service to contribute to funding the recovery efforts. Any requests for recovery would include only costs for projects the Company would have undertaken under normal operating conditions or that provide long-term value for the Company's customers. The Company does not expect this decision to have any immediate material financial impact on 1997 results. The Company has expensed, and continues to expense, the bulk of the Millstone outage costs as they are incurred. Therefore, the Company does not expect this decision to have a material financial impact on 1997 results. In a separate proceeding, the DPUC ordered the Company to submit studies by July 1, 1997 that analyze the economic benefits from the continued operation of Millstone 1 and 2. The DPUC stated that these studies were necessary in light of the uncertainty regarding restart dates of the units and the costs associated with returning these units to operation. On July 1, 1997, the Company submitted continued unit operation studies to the DPUC showing that, under base case assumptions, Millstone 1 will have a value to NU system customers (as compared to the cost of shutting down the unit and incurring replacement power costs) of approximately $70 million during the remaining thirteen years of its operating license and Millstone 2 will have a value to NU system customers (on the same assumptions as used with Millstone 1) of approximately $500 million during the remaining -67- eighteen years of its operating license. Two other cases submitted to the DPUC based on higher assumed O&M costs, which the Company considers less likely, indicated that Millstone 1 would be uneconomic in varying degrees. Based on these economic analyses, the Company expects to continue operating both Millstone 1 and Millstone 2 for the remaining terms of their respective operating licenses. The DPUC has stated it will consider these analyses in the context of the Company's next integrated resource planning proceeding which begins in April 1998. The Company cannot predict the outcome of this proceeding. In May 1996, the Connecticut state legislature enacted legislation to create the Nuclear Energy Advisory Council (NEAC), a volunteer group of fourteen members. The NEAC was charged with conducting a broad review of safety and operations of the NU system's four Connecticut nuclear units and to advise the Governor, the legislature and affected municipalities on these issues. The NEAC issued its first report on February 7, 1997, which provided a wide range of preliminary recommendations, including legislation and additional public hearings related to nuclear spent fuel, federal congressional hearings, review by the Connecticut Attorney General of the NRC's oversight of the NU system's nuclear operations and the requirement for a state nuclear plant resident inspector. These recommendations are similar to various legislative proposals currently pending at the state legislature related to nuclear oversight, operations and cost recovery. Management cannot predict the ultimate effect of this report or such proposed legislation. Demand-Side Management The Company provides demand-side management (DSM) programs for its residential, commercial and industrial customers. The Company is allowed to recover DSM costs in excess of costs reflected in base rates over periods ranging from approximately two to ten years. On April 9, 1996, the DPUC issued an order approving the Company's budget of $37.1 million for 1996 DSM expenditures, which will be recovered over a 2.43-year amortization period. In November 1996, the Company filed its 1996 DSM program and forecasted conservation adjustment mechanism (CAM) for 1997 with the DPUC. The filing proposed expenditures of $36 million in 1997. In April 1997, the DPUC approved 1997 expenditures of $36 million. The Company's unrecovered DSM costs at December 31, 1996, excluding carrying costs, which are collected currently, were approximately $90 million. Resource Plans Construction The Company's construction program in the period 1997 through 2001 is estimated as follows: 1997 1998 1999 2000 2001 ---- ---- ---- ---- ---- (Millions) $148 $180 $164 $163 $170 -68- The 1997 data include costs of approximately $18 million related to upgrading the Company's transmission facilities to meet capacity needs caused by the extended Millstone outages. See "--Electric Operations-- Distribution and Load." The construction program data shown above include all anticipated capital costs necessary for committed projects and for those reasonably expected to become committed, regardless of whether the need for the project arises from environmental compliance, nuclear safety, reliability requirements or other causes. The construction program's main focus is maintaining and upgrading the existing transmission and distribution system and nuclear and fossil-generating facilities. The construction program data shown above generally include the anticipated capital costs necessary for fossil-generating units to operate at least until their scheduled retirement dates. Whether a unit will be operated beyond its scheduled retirement date, be deactivated or be retired on or before its scheduled retirement date is regularly evaluated in light of the NU system's needs for resources at the time, the cost and availability of alternatives and the costs and benefits of operating the unit compared with the costs and benefits of retiring the unit. Retirement of certain of the units could, in turn, require substantial compensating expenditures for other parts of the NU system's bulk power supply system. Those compensating capital expenditures have not been fully identified or evaluated and are not included in the table. Future Needs The NU system periodically updates its long-range resource needs through its integrated demand and supply planning process. While the NU system does not foresee the need for any new major generating facilities at least until 2010, it has reactivated some older facilities and leased additional facilities in 1996 to supplement its capacity requirements due to the extended Millstone outages. The NU system's long-term plans rely, in part, on certain DSM programs. These NU system companies-sponsored measures, including installations to date, are projected to lower the NU system summer peak load in 2010 by 703 MW and lower the winter peak load as of January 1, 2011 by 482 MW. See "--Rates" for information about rate treatment of DSM costs. In addition, NU system companies have long-term arrangements to purchase the output from certain NUGs under federal and state laws, regulations and orders mandating such purchases. NUGs supplied 660 MW of firm capacity in 1996. The NU system companies, including the Company, do not expect to purchase additional new capacity from NUGs for the foreseeable future. See "Cogeneration Costs" in the notes to the Company's Consolidated Financial Statements, Note 1L, for information regarding the Company's renegotiation of one of its purchased-power agreements. The NU system's need for new resources may be affected by premature retirements of existing generating units, regulatory approval of the continued operation of certain fossil fuel units past scheduled retirement dates, and the possible deactivation of plants resulting from environmental -69- compliance costs, licensing decisions and other regulatory matters. The NU system's need for new resources also may be substantially affected by restructuring of the electric industry. For more information regarding restructuring, see "--Rates." Financing Program Recent Financing Activity On May 21, 1996, the Connecticut Development Authority issued $62 million of tax-exempt pollution control revenue bonds. Concurrent with that issuance, the proceeds of the bonds were loaned to the Company for the reimbursement of a portion of the Company's share of the previously incurred costs of financing, acquiring, constructing, and installing pollution control, sewage, and solid waste disposal facilities at Millstone 3. The bonds were issued with an initial variable interest rate of 3.7 percent per annum, which is reset on a weekly basis. The bonds will mature on May 1, 2031 and may bear, at the Company's discretion, a variable or fixed interest rate, which may not exceed 12 percent. The bonds were originally backed by a five-year letter of credit, which was secured by a second mortgage on the Company's interest in Millstone 1. On January 23, 1997, the letter of credit was replaced with an insurance facility and a standby bond purchase agreement. The second mortgage was replaced with the issuance of $62 million of First and Refunding Mortgage Bonds, 1996 Series B, bearing the same interest rate as the underlying bonds. On June 21, 1996, the Company entered into an operating lease agreement for the Company to acquire the use of four turbine generators having an installed cost of approximately $70 million. The initial lease term is for a five-year period. The lease agreement provides for five consecutive renewal options under which the Company may lease the turbines for five additional twelve-month terms. The rental payments are based on a 30-day floating interest rate plus 1 percent. The interest rate averaged 6.4 percent during 1996. Upon termination of the lease agreement, ownership of the turbines will remain with the lessor, unless the Company exercises its purchase option. During the first quarter of 1997, it was determined that the Company would not be in compliance with a financial coverage test required under the lease agreement. The Company has reached an agreement with the lessors for a resolution of this matter. Management believes that the terms and conditions of this agreement will not have a material adverse impact on the company's financial position or results of operations. On June 25, 1996, the Company issued $160 million of First and Refunding Mortgage Bonds, 1996 Series A. The 1996 Series A Bonds bear interest at an annual rate of 7.875%, and will mature on June 1, 2001. The net proceeds from the issuance and sale of the 1996 Series A Bonds, plus funds from other sources, were used to repay approximately $193.3 million in principal amount of the Company's Series UU bonds, which matured April 1, 1997. On July 11, 1996, the Company entered into an agreement to sell up to $200 million of fractional undivided percentage interests in its eligible accounts receivable and accrued utility revenues with limited recourse. The agreement provides for a loss reserve pursuant to which additional customer receivables may be allocated to the purchaser on an interim basis, to protect -70- against bad debt. To the extent actual loss experience of the pool receivables exceeds the loss reserve, the purchaser absorbs the excess. For receivables sold, the Company has retained collection and servicing responsibilities as agent for the purchaser. In order to comply with new accounting requirements, which were effective January 1, 1997, the Company's accounts receivable sales agreement is being restructured. On November 21, 1996, NU, the Company and WMECO entered into a new three-year Revolving Credit Agreement (the New Credit Agreement) with a group of banks. On May 30, 1997, the New Credit Agreement was amended to reflect (i) the provision by the Company of first mortgage bonds in the principal amount of $225,000,000 and by WMECO of first mortgage bonds in the principal amount of $90,000,000 as collateral for their respective obligations under the New Credit Agreement (ii) revised financial covenants consistent with NU's, the Company's and WMECO's financial forecasts, and (iii) an upfront payment to the lenders in order to maintain commitments under the New Credit Agreement. Following such amendment, the Company is able to borrow up to approximately $225,000,000 (which may increase to approximately $313,750,000 with the provision of additional first mortgage bonds as collateral in an amount which would bring the total Company collateral to $313,750,000) and WMECO will be able to borrow up to approximately $90,000,000 (which may increase to approximately $150,000,000 with the provision of additional first mortgage bonds as collateral in an amount which would bring total WMECO collateral to $150,000,000), subject to a total borrowing limit of $313,750,000 for all three borrowers. NU will be able to borrow up to $50,000,000 when each of the parties to the New Credit Agreement has maintained a consolidated operating income to consolidated interest expense ratio of at least 2.50 to 1 for two consecutive fiscal quarters. For information regarding issues related to financial covenants under the New Credit Agreement, see "--Financing Limitations" below. On April 17, 1997, the holders of approximately $38 million of notes issued by RRR required RRR to repurchase the notes at par. The notes are secured by real estate leases between RRR as lessor and NUSCO as lessee. On July 1, 1997, RRR received commitments for the purchase of approximately $12 million of notes and RRR repurchased the remaining $26 million of notes on July 14, 1997. On July 30, 1997, approximately $6 million of the $12 million was purchased by an alternative purchaser. The remaining $6 million of the notes is expected to be purchased by another purchaser by September 2, 1997. See the notes to the Company's Consolidated Financial Statements, Note 11G for further information. Total Company debt, including short term and capitalized lease obligations, was approximately $2.3 billion as of June 30, 1997, compared with $2.19 billion as of December 31, 1996. For more information regarding Company financing, see the notes to the Company's Consolidated Financial Statements and "Management's Discussion and Analysis of Financial Condition and Results of Operations." In April, 1997, Moody's downgraded most of the securities ratings of the Company and WMECO because of the extended Millstone outages. In May, 1997, S&P downgraded the Company and WMECO securities as a result of the Connecticut legislature's failure to approve a utility restructuring bill during the recently completed legislative session. As a result, all Company -71- securities are currently rated below investment grade by Moody's and S&P. These actions will adversely affect the availability and cost of funds for the Company. 1997 Financing Requirements The Company's aggregate capital requirements for 1997, exclusive of requirements under the Niantic Bay Fuel Trust (NBFT) are approximately as follows:
(Millions) Construction $148 Nuclear Fuel 5 Maturities 204 ---- Total $357
For further information on NBFT and the Company's financing of its nuclear fuel requirements, see "Leases" in the notes to the Company's Consolidated Financial Statements. For further information on the Company's 1997 and five-year financing requirements, see "Long-Term Debt" in the notes to the Company's Consolidated Financial Statements and "Management's Discussion and Analysis of Financial Condition and Results of Operations." For further information concerning the Company's financing of operations, see "--Overview of Nuclear and Related Financial Matters" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." Financing Limitations The Company's charter and many of its borrowing facilities contain financial limitations (as discussed more fully below) that must be satisfied before borrowings can be made and for outstanding borrowings to remain outstanding. The amount of short term borrowings that may be incurred by the Company is subject to periodic approval by the Commission under the Public Utility Holding Company Act of 1935 (the Holding Company Act). As of January 1, 1997, the Company's maximum authorized short term borrowing limit was $375 million. At December 31, 1996, the Company had no short-term borrowings outstanding. At June 30, 1997, the Company had short term borrowings of $100 million. The supplemental indentures under which NU issued $175 million in principal amount of 8.58 percent amortizing notes in December 1991 and $75 million in principal amount of 8.38 percent amortizing notes in March 1992 contain restrictions on dispositions of certain NU system companies' stock, limitations of liens on NU assets and restrictions on distributions on and acquisitions of NU stock. Under these provisions, neither NU nor the Company may dispose of voting stock of the Company other than to NU or another NU system company, except that the -72- Company may sell voting stock for cash to third persons if so ordered by a regulatory agency so long as the amount sold is not more than 19 percent of the Company's voting stock after the sale. The Company's charter contains preferred stock provisions restricting the amount of unsecured debt the Company may incur. As of June 30, 1997, the Company's charter permits the Company to incur an additional $408,914,000 of unsecured debt. In connection with NU's acquisition of PSNH, the DPUC imposed certain financial conditions intended to prevent NU from relying on the Company's resources if the PSNH acquisition strained NU's financial condition. The principal conditions provided for a DPUC review if the Company's common equity ratio falls to 36 percent or below, require NU to obtain DPUC approval to secure NU financings with the Company's stock or assets and obligate NU to use its best efforts to sell the Company's preferred or common stock to the public if NU cannot meet the Company's need for equity capital. If, at any time, the Company projects that its common equity ratio as of the end of the next fiscal quarter will be below 36% or plans to take any action that will result or can reasonably be expected to result in reducing the above ratio below 36% then the Company is required to notify the DPUC in writing at least 45 days before such action is taken or event is anticipated to occur. The DPUC may conduct a proceeding after its receipt of the Company's notice. At June 30, 1997, the Company's common equity ratio was 34.1 percent. The Company did not expect to meet this condition as of June 30, 1997 and notified the DPUC in accordance with the foregoing requirement. While not directly restricting the amount of short term debt that the Company, WMECO, RRR, NNECO and NU may incur, the revolving credit agreements to which the Company, WMECO, HWP, RRR, NNECO and NU are parties provide that the lenders are not required to make additional loans, and that the maturity of indebtedness can be accelerated, if NU (on a consolidated basis) does not meet a common equity ratio test that requires, in effect, that NU's consolidated common equity (as defined) be not less than 30 percent for any three consecutive fiscal quarters. At June 30, 1997, NU's common equity ratio was 32.7 percent. Additionally, under the New Credit Agreement, the Company is prohibited from incurring additional debt unless it is able to demonstrate, on a pro forma basis for the prior quarter and going forward, that its equity ratio will be at least 31 percent of its total capitalization through December 31, 1997 and 32 percent thereafter. At June 30, 1997, the Company's common equity ratio was 32.8 percent. Beginning in the fourth quarter of 1997, the Company must demonstrate that its ratio of operating income to interest expense will be at least 1.25 to 1 through December 31, 1997; 1.50 to 1 from January 1, 1998 through June 30, 1998; 2.00 to 1 from July 1, 1998 through September 30, 1998 and 2.50 to 1 thereafter. For the three month period ending June 30, 1997, the Company's interest coverage ratio (computed in accordance with the New Credit Agreement) was negative, (0.97) to 1. The Indenture provides that additional bonds may not be issued, except for certain refunding purposes, unless earnings (as defined in the Indenture and before income taxes) are at least twice the pro forma annual interest charges on outstanding bonds and certain prior lien obligations and -73- the bonds to be issued. The Company's 1996 earnings do not permit it to meet those earnings coverage tests, but as of June 30, 1997, after giving effect to the amendment of the Indenture to eliminate requirements for the sinking and improvement fund previously set forth therein, and after giving effect to the issue of the Old Bonds, the Company would be able to issue up to approximately $128 million of additional first mortgage bonds on the basis of previously issued but refunded bonds, without having to meet the earnings coverage test. The preferred stock provisions of the Company's charter also prohibit the issuance of additional preferred stock (except for refinancing purposes) unless income before interest charges (as defined and after income taxes and depreciation) is at least 1.5 times the pro forma annual interest charges on indebtedness and the annual dividend requirements on preferred stock that will be outstanding after the additional stock is issued. The Company is currently unable to issue additional preferred stock under these provisions. The supplemental indentures under which the Company's first mortgage bonds have been issued limit the amount of cash dividends and other distributions the Company can make to NU out of its retained earnings. As of June 30, 1997, the Company's retained earnings were $72.8 million below the required level for payment of dividends, and the Company is not expected to be able to declare any dividends under these provisions in 1997. Certain subsidiaries of NU, including the Company, have established a money pool (Money Pool), a system for the pooling of funds established by certain of the NU system companies to provide a more effective use of their cash resources and to reduce outside short-term borrowings. NUSCO administers the Money Pool as agent for the participating companies. Short-term borrowing needs of the participating companies (except NU) are first met with available funds of other member companies, including funds borrowed by NU from third parties. NU may lend to, but not borrow from, the Money Pool. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate, except that borrowings based on loans from NU bear interest at NU's cost. Funds may be withdrawn or repaid to the Money Pool at any time without prior notice. Other Regulatory and Environmental Matters Environmental Regulation General The NU system and its subsidiaries are subject to federal, state and local regulations with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Similarly, the NU system's major generation and transmission facilities may not be constructed or significantly modified without a review by the applicable state agency of the environmental impact of the proposed construction or modification. Compliance with environmental laws and regulations, particularly air and water pollution control requirements, may -74- limit operations or require substantial investments in new equipment at existing facilities. See "--Resource Plans" for a discussion of the NU system's construction plans. Surface Water Quality Requirements The Federal Clean Water Act (CWA) requires "point source" discharge of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the United States Environmental Protection Agency (EPA) or state environmental agency specifying the allowable quantity and characteristics of its effluent. NU system facilities have all required NPDES permits in effect. Compliance with NPDES and state water discharge permits has necessitated substantial expenditures and may require further expenditures because of additional requirements that could be imposed in the future. For information regarding ongoing criminal and civil investigations by the Office of the U.S. Attorney for the District of Connecticut and the Connecticut Attorney General related to allegations that there were some violations of certain facilities' NPDES permits, see "Legal Proceedings." In October 1995, the Connecticut Department of Environmental Protection (CDEP) issued a consent order to the Company and the Long Island Lighting Company (LILCO) requiring those companies to address leaks of dielectric fluids from the Long Island cable, which is jointly owned by the Company and LILCO. This cable enables the Company to interchange up to 300 MW of capacity with LILCO. In May 1996, the consent order was modified to address issues relating to a leak, which occurred in January 1996. The modified order requires the Company and LILCO to study and propose alternatives for the prevention, detection and mitigation of leaks from the cable and to evaluate the ecological effects of leaks on the environment. Alternatives to be studied include cable replacement and alternative dielectric fluids. These studies are ongoing. The NU system will incur additional costs to meet the requirements of the order and to meet any subsequent CDEP requirements that may result from these studies. These costs, as well as the long-term future and cost-effectiveness of the cable operation subsequent to any additional CDEP requirements, cannot be estimated at this time. The United States Attorney's Office in New Haven, Connecticut has commenced an investigation and issued subpoenas to the Company, NU, NUSCO, CONVEX and LILCO seeking documents relating to operation and maintenance of the cable and the most recent leaks from the cable described above. The government has not revealed the scope of its investigation, so management cannot evaluate the likelihood of a criminal proceeding being initiated at this time. However, management is aware of nothing that would suggest that any NU system company, officer or employee has engaged in conduct that would warrant a criminal proceeding. For information regarding a lawsuit related to discharges from the cable, see "Legal Proceedings." The ultimate cost impact of the CWA and state water quality regulations on the Company cannot be estimated because of uncertainties such as the impact of changes to the effluent guidelines or water quality standards. Additional modifications, in some cases extensive and involving substantial cost, may ultimately be required for some or all of the Company's generating facilities. -75- The Federal Oil Pollution Act of 1990 (OPA 90) sets out the requirements for facility response plans and periodic inspections of spill response equipment at facilities that can cause substantial harm to the environment by discharging oil or hazardous substances into the navigable waters of the United States and onto adjoining shorelines. The NU system companies, including the Company, are currently in compliance with the requirements of OPA 90. OPA 90 includes limits on the liability that may be imposed on persons deemed responsible for release of oil. The limits do not apply to oil spills caused by negligence or violation of laws or regulations. OPA 90 also does not preempt state laws regarding liability for oil spills. In general, the laws of the states in which the Company owns facilities and through which the Company transports oil could be interpreted to impose strict liability for the cost of remediating releases of oil and for damages caused by releases. The NU system currently carries general liability insurance in the total amount of $100 million per occurrence for oil spills. Air Quality Requirements The Clean Air Act Amendments of 1990 (CAAA) impose stringent requirements on emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX) for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Installation of continuous emissions monitors (CEMs) and expanded permitting provisions also are included. Existing and future federal and state air quality regulations, including recently proposed standards, could hinder or possibly preclude the construction of new, or the modification of existing, fossil units in the NU system's service area and could raise the capital and operating cost of existing units. The ultimate cost impact of these requirements on the NU system cannot be estimated because of uncertainties about how EPA and the states will implement various requirements of the CAAA. Nitrogen Oxide. Title I of the CAAA identifies NOX emissions as a -------------- precursor of ambient ozone. Connecticut, Massachusetts and New Hampshire, as well as other Northeastern states, currently exceed the ambient air quality standard for ozone. Pursuant to the CAAA, states exceeding the ozone standard must implement plans to address ozone nonattainment. All three states have issued final regulations to implement Phase I reduction requirements and the NU system has met these requirements. Compliance with Phase I requirements has cost the NU system a total of approximately $41 million including $10 million for the Company. Compliance has been achieved using a combination of currently available technology, combustion efficiency improvements and emissions trading. Compliance costs for Phase II, effective in 1999, are expected to result in an additional cost of approximately $5 million for the Company. Sulfur Dioxide. The CAAA mandates reductions in SO2 emissions to -------------- control acid rain. These reductions are to occur in two phases. First, certain high SO2 emitting plants were required to reduce their emissions beginning in 1995. All Phase I units have been allocated SO2 allowances for the period 1995-1999. These allowances are freely tradable. One allowance entitles a source -76- to emit one ton of SO2. No unit may emit more SO2 than the amount for which it has allowances. The only NU system units subject to the Phase I reduction requirements are PSNH's Merrimack Units 1 and 2. Newington Station in New Hampshire and Mt. Tom Station in Massachusetts are conditional Phase I units, which means that the NU system can decide to include these plants as Phase I units during any year and obtain allowances for that year. The NU system included these plants as Phase I units in 1996. On January 1, 2000, the start of Phase II, a nationwide cap of 8.9 million tons per year of utility SO2 emissions will be imposed and existing units will be granted allowances to emit SO2. Most of the NU system companies' allocated allowances will substantially exceed their expected SO2 emissions for 2000 and subsequent years, except for PSNH, which expects to purchase additional SO2 allowances. New Hampshire and Massachusetts have each instituted acid rain control laws that limit SO2 emissions. The NU system is meeting the new SO2 limitations by using natural gas and/or lower sulfur coal in its plants. Under the existing fuel adjustment clauses in Connecticut, New Hampshire and Massachusetts, the NU system should be able to recover the additional fuel costs of compliance with the CAAA and state laws from its customers. Management does not believe that the acid rain provisions of the CAAA will have a significant impact on the NU system's overall costs or rates due to the very strict limits on SO2 emissions already imposed by Connecticut, New Hampshire and Massachusetts. In addition, management believes that Title IV of the CAAA (acid rain) requirements for NOX limitations will not have a significant impact on NU system costs due to the more stringent NOX limitations resulting from Title I of the CAAA discussed above. EPA, Connecticut, New Hampshire and Massachusetts regulations also include other air quality standards, emission standards and monitoring and testing and reporting requirements that apply to the NU system's generating stations. They require new or modified fossil fuel-fired electric generating units to operate within stringent emission limits. The NU system could incur additional costs to meet these requirements, which costs cannot be estimated at this time. Air Toxics. Title III of the CAAA directed EPA to study air toxics ---------- and mercury emissions from fossil fired steam electric generation units to determine if they should be regulated. EPA exempted these plants from the hazardous air pollutant program pending completion of the studies, expected in 1997 or 1998. Should EPA determine that such generating plants' emissions must be controlled to the same extent as emissions from other sources under Title III, the NU system, including the Company, could be required to make substantial capital expenditures to upgrade or replace pollution control equipment, but the amount of these expenditures cannot be readily estimated. -77- Toxic Substances and Hazardous Waste Regulations PCBs. Under the federal Toxic Substances Control Act of 1976 (TSCA), ---- EPA has issued regulations that control the use and disposal of polychlorinated biphenyls (PCBs). PCBs had been widely used as insulating fluids in many electric utility transformers and capacitors before TSCA prohibited any further manufacture of such PCB equipment. NU system companies have taken numerous steps to comply with these regulations and have incurred increased costs for disposal of used fluids and equipment that are subject to the regulations. In general, the NU system sends fluids with concentrations of PCBs equal to or higher than 500 ppm to an unaffiliated company to dispose of using approved methods. Electrical capacitors that contain PCB fluid are sent off-site to dispose of through burning in high temperature incinerators approved by EPA. The NU system disposes of solid wastes containing PCBs in secure chemical waste landfills. Asbestos. Federal, Connecticut, New Hampshire and Massachusetts -------- asbestos regulations have required the NU system to expend significant sums in the past on removal of asbestos, including measures to protect the health of workers and the general public and to properly dispose of asbestos wastes. Asbestos removal costs for the NU system are not expected to be material in 1997. RCRA. Under the federal Resource Conservation and Recovery Act of ---- 1976, as amended (RCRA), the generation, transportation, treatment, storage and disposal of hazardous wastes are subject to EPA regulations. Connecticut, New Hampshire and Massachusetts have adopted state regulations that parallel RCRA regulations but in some cases are more stringent. The procedures by which NU system companies handle, store, treat and dispose of hazardous wastes are regularly revised, where necessary, to comply with these regulations. Hazardous Waste Liability. As many other industrial companies have ------------------------- done in the past, NU system companies disposed of residues from operations by depositing or burying such materials on-site or disposing of them at off-site landfills or facilities. Typical materials disposed of include coal gasification waste, fuel oils, gasoline and other hazardous materials that might contain PCBs. It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks. The NU system has recorded a liability for what it believes is, based upon currently available information, its estimated environmental remediation costs for waste disposal sites for which the NU system companies expect to bear legal liability, and continues to evaluate the environmental impact of its former disposal practices. Under federal and state law, government agencies and private parties can attempt to impose liability on NU system companies for such past disposal. As of June 30, 1997, the liability recorded by the Company for its estimated environmental remediation costs for known sites needing remediation, including those sites described below, exclusive of recoveries from insurance or third parties, was approximately $7.8 million. These costs could be significantly higher if alternative remedies become necessary. -78- Under the federal Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, commonly known as Superfund, EPA has the authority to cleanup or order cleanup of hazardous waste sites and to impose the cleanup costs on parties deemed responsible for the hazardous waste activities on the sites. Responsible parties include the current owner of a site, past owners of a site at the time of waste disposal, waste transporters and waste generators. It is EPA's position that all responsible parties are jointly and severally liable, so that any single responsible party can be required to pay the entire costs of cleaning up the site. As a practical matter, however, the costs of cleanup are usually allocated by agreement of the parties, or by the courts on an equitable basis among the parties deemed responsible, and several federal appellate court decisions have rejected EPA's position on strict joint and several liability. Superfund also contains provisions that require NU system companies to report releases of specified quantities of hazardous materials and require notification of known hazardous waste disposal sites. NU system companies are in compliance with these reporting and notification requirements. The NU system currently is involved in two Superfund sites in Connecticut, one in Kentucky, one in New Jersey and two in New Hampshire. The level of study of each site and the information about the waste contributed to the site by the NU system and other parties differs from site to site. Where reliable information is available that permits the NU system to make a reasonable estimate of the expected total costs of remedial action and/or the NU system's likely share of remediation costs for a particular site, those cost estimates are provided below. All cost estimates were made in accordance with generally accepted accounting principles where remediation costs were probable and reasonably estimable. Any estimated costs disclosed for cleaning up the sites discussed below were determined without consideration of possible recoveries from third parties, including insurance recoveries. Where the NU system has not accrued a liability, the costs either were not material or there was insufficient information to accurately assess the NU system's exposure. At two Connecticut sites, the Beacon Heights and Laurel Park landfills, the major parties formed coalitions and joined as defendants a number of other parties including "Northeast Utilities (Connecticut Light and Power)". Litigation on both sites was consolidated in a single case in the federal district court. In 1993, the coalitions' claims against a number of defendants including NU (CL&P) were dismissed. In 1994, the Beacon Heights Coalition indicated that they would not pursue NU (CL&P) as a defendant. As a result, the Company does not expect to incur cleanup costs for the Beacon Heights site. Meanwhile, the coalitions appealed the 1993 federal district court dismissal, which was overturned. A petition for rehearing was filed and it is unlikely the district court will take further action until the petition is resolved. In any event, the Company's liability at the Laurel Park site is expected to be minimal because of the non-hazardous nature and small volume of the materials that were sent there. The NU system had sent a substantial volume of LLRW from Millstone 1, Millstone 2 and CY to the Maxey Flats nuclear waste disposal site in Fleming County, Kentucky. On April 18, 1996, the U.S. District Court for the Eastern District of Kentucky approved a consent decree between EPA and members of the Maxey Flats PRP Steering Committee, including NU system companies, and several federal government agencies, including DOE and the Department of Defense -79- as well as the Commonwealth of Kentucky. The NU system has recorded a liability for future remediation costs for this site based on its share of ultimate remediation costs under the tentative agreement. The NU system's liability at the site has been assessed at slightly over $1 million. The Company, as successor to The Hartford Electric Light Company (HELCO), has been named as one of over 100 defendants in a cost recovery action filed in the federal district court in New Jersey. Plaintiffs have not disclosed the amount of the recovery they are seeking and, due to the nature of HELCO's limited dealings with the plaintiffs, the Company believes its liability is minimal. As discussed below, in addition to the remediation efforts for the above-mentioned Superfund sites, the NU system has been named as a PRP and is monitoring developments in connection with several state environmental actions. In 1987, CDEP published a list of 567 hazardous waste disposal sites in Connecticut. The Company owns two sites on this list. The Company has spent approximately $2.7 million, as of December 31, 1996, completing investigations and limited remediation at these sites. Both sites were formerly used by CL&P predecessor companies for the manufacture of coal gas (also known as town gas sites) from the late 1800s to the 1950s. This process resulted in the production of coal tar and creosote residues and other byproducts, which, when not sold for other industrial or commercial uses, were frequently deposited on or near the production facilities. Site investigations have been completed at these sites and discussions with state regulators are in progress to address the need and extent of remediation necessary to protect public health and the environment. One of the sites is a 25.8-acre site located in the south end of Stamford, Connecticut. Site investigations have located coal tar deposits covering approximately 5.5 acres and having a volume of approximately 45,000 cubic yards. A final risk assessment report for the site was completed in January 1994. The NU system is currently considering redevelopment of the site in cooperation with the local municipality as part of the State of Connecticut's Urban Sites Program. Several remedial options have been evaluated to remediate the site, if necessary to accommodate redevelopment. The estimated cost of remediation and institutional controls ranges from $5 to $8 million. The second site is a 3.5-acre former coal gasification facility that currently serves as an active substation in Rockville, Connecticut. Site investigations have located creosote and other polyaromatic hydrocarbon contaminants. The Company has provided to the CDEP and local officials the Company's plan to determine whether any remediation of the site will be necessary or advisable. As part of the 1989 divestiture of the Company's gas business, site investigations were performed for properties that were transferred to Yankee Gas Services Company (Yankee Gas). The Company agreed to accept liability for any required cleanup for the three sites it retained. These three sites include Stamford and Rockville (discussed above) and Torrington, Connecticut. At the Torrington site, investigations have been completed and the cost of any remediation, if necessary, -80- is not expected to be material. The Company and Yankee Gas also share a site in Winsted, Connecticut and any liability for required cleanup there. The Company and Yankee Gas will share the costs of cleanup of sites formerly used in the Company's gas business but not currently owned by either of them. In the past, the NU system has received other claims from government agencies and third parties for the cost of remediating sites not currently owned by the NU system but affected by past NU system disposal activities and may receive more such claims in the future. The NU system expects that the costs of resolving claims for remediating sites about which it has been notified will not be material, but cannot estimate the costs with respect to sites about which it has not been notified. Electric and Magnetic Fields In recent years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Most researchers, as well as numerous scientific review panels considering all significant EMF epidemiological and laboratory research to date, agree that current information remains inconclusive, inconsistent and insufficient for risk assessment of EMF exposures. Most recently, a review issued in October 1996 by the U.S. National Academy of Sciences concluded "that the current body of evidence does not show that exposure to these fields presents a human-health hazard." Based on this information management does not believe that a causal relationship between EMF exposure and adverse health effects has been established or that significant capital expenditures are appropriate to minimize unsubstantiated risks. The NU system is closely monitoring research and government policy developments. The NU system supports further research into the subject and is voluntarily participating in the funding of the ongoing National EMF Research and Public Information Dissemination Program. If further investigation were to demonstrate that the present electricity delivery system is contributing to increased risk of cancer or other health problems, the industry could be faced with the difficult problem of delivering reliable electric service in a cost-effective manner while managing EMF exposures. In addition, if the courts were to conclude that individuals have been harmed and that utilities are liable for damages, the potential monetary exposure for all utilities, including the NU system companies, could be enormous. Without definitive scientific evidence of a causal relationship between EMF and health effects, and without reliable information about the kinds of changes in utilities' transmission and distribution systems that might be needed to address the problem, if one is found, no estimates of the cost impacts of remedial actions and liability awards are available. The Connecticut Interagency EMF Task Force (Task Force) last provided a report to the state legislature in January 1995. The Task Force advocated a policy of "voluntary exposure control," which involves providing people with information to enable them to make individual decisions about EMF exposure. Neither the Task Force, nor any Connecticut state agency, has recommended changes to the existing electrical supply system. The Task Force is required to provide another -81- report to the legislature by 1998. The Connecticut Siting Council (Siting Council) previously adopted a set of EMF "Best Management Practices," which are now considered in the justification, siting and design of new or modified transmission lines and substations. In 1996, the Siting Council concluded a generic proceeding in which it conducted a comparative life- cycle cost analysis of overhead and underground transmission lines, pursuant to a law that was adopted in 1994 in part due to public EMF concerns. This proceeding is expected to be referenced in future comparisons of overhead and underground alternatives to proposed transmission line projects. EMF has become increasingly important as a factor in facility siting decisions in many states, and local EMF concerns occasionally make the news when utilities propose new or changed facilities. In prior years, various bills involving EMF were introduced in the Massachusetts and Connecticut legislatures with no action taken. No such bills were introduced in either state in 1996. The Company has been the focus of media reports since 1990 charging that EMF associated with a substation and related distribution lines in Guilford, Connecticut are linked with various cancers and other illnesses in several nearby residents. See "Legal Proceedings" for information about two suits brought by plaintiffs who now or formerly lived near that substation. FERC Hydro Project Licensing Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by FERC. Upon the expiration of a license, any hydroelectric project so licensed is subject to reissuance by FERC to the existing licensee or to others upon payment to the licensee of the lesser of fair value or the net investment in the project plus severance damages less certain amounts earned by the licensee in excess of a reasonable rate of return. The NU system companies hold FERC licenses for 19 hydroelectric projects aggregating approximately 1,375 MW of capacity, located in Connecticut, Massachusetts and New Hampshire. The Company's FERC licenses for operation of the Falls Village and Housatonic Hydro Projects expire in 2001. The relicensing process was initiated in August of 1996 with the issuance of a Notice of Intent (NOI) to the FERC indicating the intention of the Company to relicense both projects. An Initial Consultation Document (ICD) was issued to consulting agencies in September 1996 and two public meetings were held in early November 1996 to discuss relicensing issues. The Company is awaiting the submittal of resource agency comments. FERC has issued a notice indicating that it has authority to order project licensees to decommission projects that are no longer economic to operate. FERC has not required any such project decommissioning to date. The potential costs of decommissioning a project, however, could be substantial. It is likely that this FERC decision will be appealed if, and when, they attempt to exercise this authority. -82- EMPLOYEES As of December 31, 1996, the NU system companies had 8,842 full and part-time employees on their payrolls, of which 2,194 were employed by the Company, 1,279 by PSNH, 497 by WMECO, 92 by HWP, 1,274 by NNECO, 2,692 by NUSCO and 814 by NAESCO. NU, NAEC, Charter Oak, Mode 1 Communications, Inc. and Select Energy, Inc. have no employees. In 1995 and early 1996, the NU system implemented a program to reduce the nuclear organization's total workforce by approximately 220 employees, which included both early retirements and involuntary terminations. The pretax cost of the program was approximately $8.7 million. For information regarding the criminal investigations by the NRC's Office of Investigation and the Office of the U.S. Attorney for the District of Connecticut related to this workforce reduction, see "Legal Proceedings." In December 1996, the NU system announced a voluntary separation program affecting approximately 1,100 employees. The separations will be effected between April 1, 1997 and March 1, 1998. The estimated cost of the program is approximately $7 million. Approximately 2,200 employees of the Company, PSNH, WMECO, NAESCO and HWP are covered by 11 union agreements, which expire between October 1, 1997 and May 31, 1999. PROPERTIES The Company's principal plants and other properties are located either on land which is owned in fee or on land, as to which the Company owns perpetual occupancy rights adequate to exclude all parties except possibly state and federal governments, which has been reclaimed and filled pursuant to permits issued by the United States Army Corps of Engineers. In addition, the Company has certain substation equipment, data processing equipment, nuclear fuel, gas turbines, nuclear control room simulators, vehicles, and office space that are leased. With few exceptions, the Company's lines are located on or under streets or highways, or on properties either owned or leased, or in which the Company has appropriate rights, easements, or permits from the owners. Substantially all of the Company's properties are subject to the lien of the Indenture, subject to the exceptions described herein. See "Description of the New Bonds--Security." In addition, the Company's interest in Millstone 1 is subject to second liens for the benefit of lenders under agreements related to pollution control revenue bonds. Various of these properties are also subject to minor encumbrances which do not substantially impair the usefulness of the properties to the Company. The Company believes its properties to be well maintained and in good operating condition. -83- Transmission and Distribution System At December 31, 1996, the NU system companies owned 103 transmission and 416 distribution substations that had an aggregate transformer capacity of 25,200,069 kilovolt amperes (kVa) and 9,127,367 kVa, respectively, 3,057 circuit miles of overhead transmission lines ranging from 69 kilovolt (kV) to 345 kV, and 192 cable miles of underground transmission lines ranging from 69 kV to 138 kV; 32,649 pole miles of overhead and 1,958 conduit bank miles of underground distribution lines; and 398,452 line transformers in service with an aggregate capacity of 16,472,221 kVa. Electric Generating Plants As of June 30, 1997, the electric generating plants, including leased property, of the Company and the Company's entitlements in the generating plants of the two operating Yankee regional nuclear generating companies were as follows:
Claimed Year Capability* Plant Name (Location) Type Installed (kilowatts) - ------------------------------ -------------------- --------------------- --------------------- Millstone (Waterford, CT) Unit 1 Nuclear 1970 524,637 Unit 2 Nuclear 1975 708,345 Unit 3 Nuclear 1986 606,453 Seabrook (Seabrook, NH) Nuclear 1990 47,175 VY (Vernon, VT) Nuclear 1972 45,353 --------- Total Nuclear-Steam Plants (6 Units) 1,931,963 Total Fossil-Steam Plants (10 Units) 1954-73 1,875,000 Total Hydro-Conventional (25 Units) 1903-55 98,970 Total Hydro-Pumped Storage (7 Units) 1928-73 905,150 Total Internal Combustion (21 Units) 1966-96 601,510 --------- Total CL&P Generating Plant (69 Units) 5,412,593 =========
* Claimed capability represents winter ratings as of June 30, 1997 Franchises For more information regarding recent regulatory and legislative decisions and initiatives that may affect the terms under which the Company provides electric service in its franchised territory, see "--Rates-- Electric Industry Restructuring in Connecticut," and "Legal Proceedings." Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, the Company has, subject to certain exceptions not deemed material, valid -84- franchises free from burdensome restrictions to sell electricity in the respective areas in which it is now supplying such service. In addition to the right to sell electricity as set forth above, the franchises of the Company include, among others, rights and powers to manufacture, generate, purchase, transmit and distribute electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of the Company include the power of eminent domain. LEGAL PROCEEDINGS Litigation Relating to Electric and Magnetic Fields NU and the Company are currently involved in two lawsuits alleging physical and emotional damages from exposure to "electromagnetic radiation" generated by the defendants. Management believes that the allegations that EMF caused or contributed to the plaintiffs' illnesses are not supported by scientific evidence. One of these cases has been resolved in NU and the Company's favor at the trial level, but it has been appealed and is now pending at the Connecticut Supreme Court. Southeastern Connecticut Regional Resources Recovery Authority (SCRRRA)-- Application of the Municipal Rate This matter involves three separate disputes over the rates that apply to the Company's purchases of the generation of the SCRRRA project in Preston, Connecticut. A favorable ruling on all of these matters could result in savings to Company customers of approximately $20 million over the terms of the agreement with the SCRRRA. FERC has ruled in the Company's favor in one of these matters, but this decision has been appealed to the United States D.C. Circuit Court of Appeals. A final ruling in this decision in favor of the Company would also resolve the second dispute. A Connecticut Superior Court, however, has ruled in favor of the SCRRRA in the final dispute. The Company appealed this decision to the Connecticut Appellate Court, and the Connecticut Supreme Court has transferred the appeal to itself. Connecticut DPUC-CL&P's Petition for Declaratory Ruling Regarding Proposed Retail Sales of Electricity by Texas--Ohio Power, Inc. (TOP) On August 3, 1995, the Company filed a petition for declaratory rulings with the DPUC to determine whether TOP, which built a small cogeneration plant in Manchester, Connecticut, can sell electricity from the facility to two Company retail customers in Manchester. On December 6, 1995, the DPUC ruled that, because TOP's project would not use the public streets, it did not require specific legislative authorization to make retail sales of electricity. In February 1997, the Hartford Superior Court upheld the DPUC's decision. The Company has appealed the decision to the Connecticut Appellate Court. -85- Tax Litigation In 1991, the Town of Haddam performed a town-wide revaluation of the CYAPC property in that town. Based on the report of the engineering firm hired by the town to perform the revaluation, Haddam determined that the full fair-market value of the property, as of October 1, 1991, was $840 million. At that time, CY's net-book value was $245 million. On September 5, 1996, a Connecticut court ruled that Haddam had over-assessed CY at three and a half times its proper assessment. The decision set the plant's fair market value at $235 million. CYAPC estimated that the town owed it approximately $16.2 million in refunds, including accrued interest, for taxes that were overpaid from July 31, 1992 through July 31, 1996. On May 9, 1997, Haddam and CYAPC reached an agreement regarding the repayment of property taxes due CYAPC for the tax years beginning October 1, 1991 through October 1, 1995. Haddam has agreed to repay to CYAPC an amount totaling $13,990,000 which is inclusive of taxes and interest for those years. As part of this negotiated settlement, Haddam has paid CYAPC $2,000,000 and may bond all or part of the remaining $11,990,000. Long Island Cable--Citizen's Suit On April 4, 1996, a citizen's suit against Long Island Lighting Company (LILCO), a non-affiliate of NU, the Company (collectively, the Companies) and NUSCO was filed in Federal District Court in Connecticut. The suit alleges the Companies are in violation of the Federal Clean Water Act because they are maintaining an unpermitted discharge of pollutants from the Long Island Cable and claims the pollutants are an imminent danger to the environment and public health. The suit asks the Court, among other things, to enjoin further operation of the Long Island Cable without a permit and to impose a civil penalty of $25,000 for each violation. On April 23, 1997, the Company, NUSCO, LILCO and the Long Island Soundkeeper Fund, Inc. jointly filed a Stipulation of Dismissal in Federal District Court, which settled this suit. The settlement will not impose material costs on the Company or any other NU system companies. Connecticut Municipal Electric Energy Cooperative (CMEEC) Dispute This matter involves a dispute with CMEEC over its obligations under its Millstone Units 1 & 2 contract with the Company, under which CMEEC has a 3.49 percent life-of-unit interest in each of the units. CMEEC and the Company have been negotiating since May 1996 over issues related to Millstone Units 1 & 2 and have taken preliminary steps to prepare for arbitration of the matter. Since October 1996, CMEEC has failed to make payment on its obligations of approximately $1.6 million per month, claiming that the Company materially breached its contractual obligations, and requesting arbitration of the issues. The Company has denied the allegations and filed a petition on July 1, 1997 requesting the Connecticut Superior Court to order CMEEC to pay its outstanding obligations (about $13.3 million) and make continuing payments while the arbitration action is proceeding. -86- Millstone 3--Joint Owner Litigation The Company and WMECO, through NNECO as agent, operate Millstone 3 at cost, and without profit, under a Sharing Agreement that obligates them to utilize good utility operating practices and requires the joint owners to share the risk of employee negligence and other risks pro-rata in accordance with their ownership shares. The Sharing Agreement also provides that the Company and WMECO would only be liable for damages to the non-NU owners for a deliberate breach of the agreement pursuant to authorized corporate action. On August 7, 1997, the non-NU owners of Millstone 3 filed demands for arbitration with the Company and WMECO as well as lawsuits in Massachusetts Superior Court against NU and its current and former trustees. The non-NU owners raise a number of contract, tort and statutory claims, arising out of the operation of Millstone 3. The arbitrations and lawsuits seek to recover compensatory damages, punitive damages, treble damages and attorneys' fees. Owners representing approximately two-thirds of the non- NU interests in Millstone 3 have claimed compensatory damages in excess of $200 million. In addition, one of the lawsuits seeks to restrain NU from disposing of its shares of the stock of WMECO and HWP, pending the outcome of the lawsuit. The NU system companies believe there is no legal basis for the claims and intend to defend against them vigorously. NRC--Section 2.206 Petitions Spent Fuel Pool Off-Load Practices 2.206 Petition: In August 1995, a petition was filed with the NRC under Section 2.206 of the NRC's regulations by the organization We the People and a NUSCO employee. The petitioners maintained that NU's historic practice of off-loading the full reactor core at Millstone 1 resulted in spent fuel pool heat loads in excess of the pool's NRC-approved cooling capability, and asserted that the practice was a knowing and willful violation of NRC requirements. The petitioners also filed a supplemental petition concerning refueling practices at Millstone 2 and 3 and Seabrook Station. On December 26, 1996, the Acting Director of the Office of Nuclear Reactor Regulation issued a partial decision granting, in part, the petition. The decision, which is limited to the NRC staff's technical review of the issues raised by petitioners, concluded that the design of the spent fuel pool and related system at Millstone 1 was adequate, and that the full core off-load practices at that unit, Millstone 3 and Seabrook were safe. The petitioners' assertions regarding Millstone 2 were not substantiated. The Director further concluded that the regulatory actions taken by the NRC to date regarding the three Millstone units, including the imposition of an Independent Corrective Action Verification Program prior to restart, were broader than the actions requested by petitioners and thus constituted a partial grant of petitioners' request. Issues of wrongdoing raised in the petition remain under consideration by the NRC staff, and will not be addressed until after the U.S. Attorney has concluded its investigation of the spent fuel pool issues and decided whether to commence criminal proceedings. See "--NRC Office of Investigations and U.S. Attorney Investigations and Related Matters" below. -87- In March 1997, a Section 2.206 petition was filed with the NRC seeking enforcement action and the placement of certain restrictions on the decommissioning activities at the CY nuclear power plant. Specifically, the petitioners requested that the NRC issue a civil monetary penalty to assure compliance with radiation protection requirements, and that CY's license be modified to prohibit any decommissioning activities for a six month period following any radiological contamination event. In addition, petitioners requested that CY be placed on the NRC's "watch list." Management is currently evaluating whether and how to respond to this petition. Other 2.206 Petitions: Two petitions under Section 2.206 have been filed with the NRC requesting various actions be taken with respect to the operating licenses for Millstone Units 1, 2 and 3 and CY, including revocation and suspension, and other enforcement action due to alleged mismanagement of the units and violations of NRC regulations that petitioners allege have jeopardized public health and safety. While management believes that the NRC is already addressing a number of the issues raised in these petition, it cannot predict the ultimate outcome of these petition. NRC Office of Investigations and U.S. Attorney Investigations and Related Matters The NRC's Office of Investigations (OI) has been examining various matters at Millstone and CY, including but not limited to procedural and technical compliance matters and employee concerns. One of these matters has been referred, and others may be referred, to the Office of the U.S. Attorney for the District of Connecticut (U.S. Attorney) for possible criminal prosecution. The referred matter concerns full core off-load procedures and related matters at Millstone (see "--NRC--Section 2.206 Petitions"). The U.S. Attorney is also reviewing possible criminal violations arising out of certain of NNECO's other activities at Millstone and CY, including the 1996 nuclear workforce reduction and its licensed operator training programs. The U.S. Attorney, together with the U.S. EPA and the Connecticut Attorney General, is also investigating possible criminal violations of federal environmental laws at certain NU facilities, including Millstone. NU has been informed by the government that it is a target of the investigation, but that no one in senior management is either a target or a subject of the investigation. Management does not believe that any NU system company or officer has engaged in conduct that would warrant a federal criminal prosecution. NU intends to fully cooperate with the OI and the U.S. Attorney in their ongoing investigations. Connecticut DEP The Connecticut Department of Environmental Protection (DEP) has referred to the Connecticut Attorney General a series of alleged environmental violations at Millstone for a possible civil penalty action. Management does not believe that this action will have a material adverse impact on the NU system. -88- Other Legal Proceedings The following sections of this Prospectus discuss additional legal proceedings: see "Business --Overview of Nuclear Matters and Related Financial Matters" for information regarding NRC watch list issues; "Business --Rates" for information about the Company's rate and fuel clause adjustment clause proceedings, various state restructuring proceedings and civil lawsuits related thereto; "Business--Electric Operations-- Transmission Access and FERC Regulatory Changes" for information about proceedings relating to power and transmission issues; "Business--Electric Operations--Nuclear Generation" and "Business--Electric Operations--Nuclear Plant Performance and Regulatory Oversight" for information related to nuclear plant performance, nuclear fuel enrichment pricing, high-level and low-level radioactive waste disposal, decommissioning matters and NRC regulation; and "Business--Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality, toxic substances and hazardous waste, electric and magnetic fields, licensing of hydroelectric projects, and other matters. -89- MANAGEMENT AND COMPENSATION Executive Officers and Directors The following table sets forth certain information concerning the executive officers and directors of the Company as of the date of this Prospectus.
First Elected First Elected Name Positions Held an Officer a Director - ---------------------------- ----------------- ----------- ---------- Robert G. Abair D - 01/01/89 John H. Forsgren EVP, CFO, D 02/01/96 06/10/96 William T. Frain, Jr. D - 02/01/94 Cheryl W. Grise SVP, CAO, D 06/01/91 01/01/94 John B. Keane VP, TR, D 08/01/92 08/01/92 Bruce D. Kenyon P, D 09/03/96 09/03/96 Francis L. Kinney SVP 04/24/74 - Hugh C. MacKenzie P, D 07/01/88 06/06/90 Michael G. Morris CH, D 08/19/97 08/19/97 John J. Roman VP, CONT 04/01/92 - Robert P. Wax SVP, SEC, GC 08/01/92 -
Key: - ---- CAO - Chief Administrative Officer GC - General Counsel CFO - Chief Financial Officer P - President CH - Chairman SEC - Secretary CONT - Controller SVP - Senior Vice President D - Director TR - Treasurer EVP - Executive Vice President VP - Vice President
Name Age Business Experience During Past 5 Years - --------------- --- --------------------------------------- Robert G. Abair (1) 58 Elected Vice President and Chief Administrative Officer of WMECO in 1988. John H. Forsgren (2) 50 Elected Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO and NAEC February, 1996; previously Managing Director of Chase Manhattan Bank since 1995; and Senior Vice President-Chief Financial Officer of Euro Disney, The Walt Disney Company.
-90-
Name Age Business Experience During Past 5 Years - --------------- --- --------------------------------------- William T. Frain, Jr.(3) 55 Elected President and Chief Operating Officer of PSNH in 1994; previously Senior Vice President of PSNH since 1992. Cheryl W. Grise 44 Elected Senior Vice President and Chief Administrative Officer of CL&P, PSNH and NAEC, and Senior Vice President of WMECO in 1995; previously Senior Vice President-Human Resources and Administrative Services of CL&P, WMECO and NAEC since 1994; Vice President-Human Resources of NAEC since 1992. John B. Keane (4) 50 Elected Vice President and Treasurer of NU, CL&P, PSNH, WMECO and NAEC in 1993; previously Vice President, Secretary and General Counsel-Corporate of NU, CL&P and WMECO since 1992; Vice President, Assistant Secretary and General Counsel-Corporate of PSNH and NAEC, Vice President, Secretary and General Counsel-Corporate of NU and CL&P, and Vice President, Secretary, Assistant Clerk and General Counsel-Corporate of WMECO since 1992. Bruce D. Kenyon (5) 54 President and Chief Executive Officer of NAEC and President-Nuclear Group of CL&P, PSNH and WMECO since 1996; previously President and Chief Operating Officer of South Carolina Electric and Gas Company from 1990. Francis L. Kinney (6) 64 Elected Senior Vice President-Governmental Affairs of CL&P, WMECO and NAEC in 1994; previously Vice President- Public Affairs of NAEC since 1992. Hugh C. MacKenzie (7) 55 Elected President-Retail Business Group of NU February, 1996 and President of CL&P and WMECO in 1994; previously Senior Vice President-Customer Service Operations of CL&P and WMECO since 1990. Michael G. Morris (8) 50 Elected Chairman of the Board, President and Chief Executive Officer of NU, Chairman of CL&P, PSNH, WMECO and NAEC, and Chief Executive Officer of PSNH and NAEC effective August 19, 1997; previously Executive Vice President of CMS
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Name Age Business Experience During Past 5 Years - --------------- --- --------------------------------------- Energy Corporationsince 1996; President and Chief Executive Officer of Consumers Energy Company (prior to March 1997, called Consumers Power Company) since 1994; Executive Vice President and Chief Operating Officer of Consumers Power Company 1992-1994. John J. Roman 43 Elected Vice President and Controller of NU, CL&P, PSNH, WMECO and NAEC in 1995; previously Assistant Controller of CL&P, PSNH, WMECO and NAEC since 1992. Robert P. Wax 48 Elected Senior Vice President, Secretary and General Counsel of NU, CL&P, PSNH, NAEC and WMECO in 1997. Previously elected Vice President, Secretary and General Counsel of PSNH and NAEC in 1994; elected Vice President, Secretary, Assistant Clerk and General Counsel of WMECO in 1993; previously Vice President, Assistant Secretary and General Counsel of PSNH and NAEC since 1993; previously Vice President and General Counsel-Regulatory of NU, CL&P, PSNH, WMECO and NAEC since 1992.
(1) Member-Advisory Committee, Bank of Boston Springfield/Pioneer Valley. (2) Director of Connecticut Yankee Atomic Power Company. (3) Director of the Business and Industry Association of New Hampshire, the Greater Manchester Chamber of Commerce; Trustee of Optima Health, Inc. and Saint Anselm College. (4) Director of Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power Corporation, Yankee Atomic Electric Company and Connecticut Yankee Atomic Power Company, Member-Advisory Committee, Fleet Bank Connecticut. (5) Trustee of Columbia College and Director of Connecticut Yankee Atomic Power Company. (6) Director of Mid-Conn Bank. Mr. Kinney is retiring from Northeast Utilities effective September 1, 1997. (7) Director of Connecticut Yankee Atomic Power Company. (8) Trustee and member of the executive committee of the Institute of Gas Technology, and trustee of the Eastern Michigan University Foundation, the Delta Sigma Phi Foundation, the Olivet College Leadership Advisory Council, the Library of Michigan Foundation and the Institute of Nuclear Power Operations. There are no family relationships between any director or executive officer and any other director or executive officer of NU, the Company, PSNH, WMECO or NAEC. -92- Executive Compensation and Employment Agreements The Company does not directly compensate any executive officer. The following table presents the cash and non-cash compensation received by the CEO and the next four highest paid executive officers of the NU system (and indicates the position held by such officer in the Company), and by a retired executive officer who would have been among the five highest paid executive officers but for his retirement, in accordance with rules of the Securities and Exchange Commission (Commission):
Annual Compensation Long Term Compensation Awards Options/ Payouts Re- Stock Long Term All Other stricted Appreci- Incentive Other Annual Stock ation Program Compen- Name and Salary Compensa- Awards Rights Payouts sation($) Principal Position Year ($) Bonus($) tion($) ($) (#) ($) (1) - ----------------------------------------------------------------------------------------------------------------------------------- Bernard M. Fox 1996 551,300 None None None None 65,420 7,500 Chairman 1995 551,300 246,168 None None None 130,165 7,350 (Note 2) 1994 544,459 308,896 None None None 115,771 4,500 Bruce D. Kenyon 1996 144,231 400,000 None 499,762 None None None President-Nuclear (Note 3) Group (Note 2) 1995 None None None None None None None 1994 None None None None None None None John H. Forsgren 1996 305,577 None 62,390 80,380 None None None Executive Vice President (Note 4) (Note 4) and Chief Financial 1995 None None None None None None None Officer (Note 2) 1994 None None None None None None None Hugh C. MacKenzie 1996 264,904 None None None None 19,834 7,500 President-Retail 1995 247,665 128,841 None None None 46,789 7,350 Business Group 1994 245,832 113,416 None None None 40,449 4,500 (Note 2)
-93- Ted C. Feigenbaum 1996 248,858 (Note 5) None None None 14,770 7,222 (Note 2) 1995 185,300 126,002 None None None None 5,553 1994 183,331 47,739 None None None None 4,500 Robert E. Busch 1996 300,385 None None None None 26,747 2,637,500 Formerly President- (Note 6) Energy-Resources Group 1995 350,000 147,708 None None None 63,100 7,350 of NU, CL&P, WMECO 1994 346,122 173,366 None None None 44,073 4,500 and PSNH and formerly President of NAEC (Note 6)
Notes: 1. "All Other Compensation" consists of employer matching contributions under the Northeast Utilities Service Company 401(k) Plan, generally available to all eligible employees. It also includes, in the case of Mr. Busch, certain payments made to him pursuant to the terms of his separation agreement with Northeast Utilities Service Company (see Note 6). 2. See "Management and Compensation" for information on the directorships and officer positions held by each active individual named in the summary compensation table with each of the registrants. 3. The restricted stock will vest when Millstone Station is removed from the NRC's "watch list," provided that this occurs within three years of Mr. Kenyon's commencement of employment and the SRLP and INPO ratings of Seabrook Station have not materially changed from their 1996 levels. Dividends accruing on these shares are reinvested in additional shares subject to the same restrictions. At the end of 1996, Mr. Kenyon owned 39,585 restricted shares with a market value of $519,555, plus a $9,896 dividend that was reinvested into an additional 740 restricted shares on January 2, 1997. 4. The "other annual compensation" consists of tax payments on a restricted stock award. The restricted stock will vest on January 1, 1999. Dividends accruing on these shares are reinvested in additional shares subject to the same restrictions. At the end of 1996, Mr. Forsgren owned 5,305 restricted shares with a market value of $69,621, plus a $1,326 dividend that was reinvested into an additional 99 restricted shares on January 2, 1997. 5. Awards under the 1996 short term incentive program of the Northeast Utilities Executive Incentive Plan have not yet been made. Based on preliminary estimates of corporate performance, no short term awards will be made. 6. Mr. Busch left the Company during 1996. Pursuant to his separation agreement with Northeast Utilities Service Company, Mr. Busch received cash payments of $880,000 during 1996 and $220,000 during 1997, a supplemental retirement benefit with a present value of $1,400,000, continued medical coverage for himself and his family with a present value of $100,000 and career planning with a value of $30,000. See "Employment Contracts and Termination of Employment Arrangements," below. * Mr. Fox retired effective August 19, 1997. -94- Pension Benefits The following table shows the estimated annual retirement benefits payable to an executive officer of the registrant upon retirement, assuming that retirement occurs at age 65 and that the officer is at that time not only eligible for a pension benefit under the Northeast Utilities Service Company Retirement Plan (the Retirement Plan) but also eligible for the make-whole benefit and the target benefit under the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies (the Supplemental Plan). The Supplemental Plan is a non-qualified pension plan providing supplemental retirement income to NU system officers. The make- whole benefit under the Supplemental Plan, available to all officers, makes up for benefits lost through application of certain tax code limitations on the benefits that may be provided under the Retirement Plan, and includes as "compensation" awards under the Executive Incentive Compensation Program and the Executive Incentive Plan and deferred compensation (as earned). The target benefit further supplements these benefits and is available to officers at the Senior Vice President level and higher who are selected by the Board of Trustees of Northeast Utilities to participate in the target benefit and who remain in the employ of Northeast Utilities companies until at least age 60 (unless the Board of Trustees sets an earlier age). Each of the executive officers of Northeast Utilities named in the Summary Compensation Table is currently eligible for a target benefit, except Mr. Kenyon, whose Employment Agreement provides a specially calculated retirement benefit, based on his previous arrangement with South Carolina Electric and Gas. If Mr. Kenyon retires with at least three but less than five years of service with NU, he will be deemed to have five years of service. In addition, if Mr. Kenyon retires with at least three years of service with NU, he will receive a lump sum payment of $500,000. The benefits presented below are based on a straight life annuity beginning at age 65 and do not take into account any reduction for joint and survivorship annuity payments. Annual Target Benefit
Final Average Compensation Years of Credited Service ------------ ------------------------- 15 20 25 30 35 -- -- -- -- -- $200,000 $ 72,000 $ 96,000 $120,000 $120,000 $120,000 250,000 90,000 120,000 150,000 150,000 150,000 300,000 108,000 144,000 180,000 180,000 180,000 350,000 126,000 168,000 210,000 210,000 210,000 400,000 144,000 192,000 240,000 240,000 240,000 450,000 162,000 216,000 270,000 270,000 270,000 500,000 180,000 240,000 300,000 300,000 300,000 600,000 216,000 288,000 360,000 360,000 360,000 700,000 252,000 336,000 420,000 420,000 420,000 800,000 288,000 384,000 480,000 480,000 480,000 900,000 324,000 432,000 540,000 540,000 540,000
-95- 1,000,000 360,000 480,000 600,000 600,000 600,000 1,100,000 396,000 528,000 660,000 660,000 660,000 1,200,000 432,000 576,000 720,000 720,000 720,000
Final average compensation for purposes of calculating the target benefit is the highest average annual compensation of the participant during any 36 consecutive months compensation was earned. Compensation taken into account under the target benefit described above includes salary, bonus, restricted stock awards, and long-term incentive payouts shown in the Summary Compensation Table, but does not include employer matching contributions under the 401(k) Plan. In the event that an officer's employment terminates because of disability, the retirement benefits shown above would be offset by the amount of any disability benefits payable to the recipient that are attributable to contributions made by NU and its subsidiaries under long term disability plans and policies. As of December 31, 1996, the five executive officers named in the Summary Compensation Table (the Named Executive Officers) had the following years of credited service for retirement compensation purposes: Mr. Fox- 32, Mr. Kenyon-0, Mr. Forsgren-0, Mr. MacKenzie-31, and Mr. Feigenbaum-10. Assuming that retirement were to occur at age 65 for these officers, retirement would occur with 43, 11, 15, 41 and 29 years of credited service, respectively. Mr. Fox retired effective August 19, 1997. Employment Contracts and Termination of Employment Arrangements Officer Agreements NUSCO has entered into employment agreements (the Officer Agreements) with each of the Named Executive Officers (except for Mr. Fox--see separate description below) and certain other executive officers and directors of the registrants. The Officer Agreements are also binding on NU and on each majority-owned subsidiary of NU with at least fifty employees on its direct payroll. Each Officer Agreement obligates the officer to perform such duties as may be directed by the NUSCO Board of Directors or the NU Board, protect the NU system's confidential information, and refrain, while employed by the NU system and for a period of time thereafter, from competing with the Company in a specified geographic area. Each Officer Agreement provides that the officer's base salary will not be reduced below certain levels without the consent of the officer, that the officer will participate in specified benefits under the Supplemental Executive Retirement Plan (see Pension Benefits, above), in the applicable divisional officer executive incentive programs or the Stock Price Recovery Program, as the case may be, under the Executive Incentive Plan (see Report on Executive Compensation, above), and, beginning on January 1, 1999, if the employment term has not ended, in each short term and long term incentive compensation program established by the NU system for such senior level executives generally, at an incentive opportunity level not less than that in effect for the officer as of January 1, 1996 (or January 1, 1997 for certain officers). -96- Each Officer Agreement provides for automatic one-year extensions of the employment term unless at least six months' notice of non-renewal is given by either party. The employment term may also be ended by the NU system for "cause", as defined, at any time (in which case no target benefit, if any, shall be due the officer under the Supplemental Executive Retirement Plan), or by the officer on thirty days' prior written notice for any reason. Absent "cause", the NU system may remove the officer from his or her position on sixty days' prior written notice, but in the event the officer is so removed and signs a release of all claims against the NU system, the officer will receive one or two years' base salary and annual incentive payments, specified employee welfare and pension benefits, and vesting of stock appreciation rights, options and restricted stock. Under the terms of an Officer Agreement, upon any termination of employment of the officer within two years following a change in control, as defined, if the officer signs a release of all claims against the NU system the officer will be entitled to certain payments including two or three times base salary and annual incentive payments, specified employee welfare and pension benefits, and vesting of stock appreciation rights, options and restricted stock. Certain of the change in control provisions may be modified by the Board of Trustees prior to a change in control, on at least two years' notice to the affected officer(s). Besides the terms described above, Mr. Forsgren's Officer Agreement provides for a starting salary of $350,000 per year and a $100,000 restricted stock grant. Mr. Feigenbaum's Officer Agreement provides for a starting salary of $250,000 per year. Mr. Kenyon's Officer Agreement provides for an initial starting salary of at $500,000 per year, a $500,000 restricted stock grant and a $400,000 cash signing bonus (See Summary Compensation Table, above). Mr. Kenyon's Officer Agreement also provides for a special retirement benefit (described above in Pension Benefits) instead of a target benefit and a make-whole benefit under the Supplemental Plan, and a special short term incentive compensation program in lieu of a portion of the Stock Price Recovery Program. Under this incentive program Mr. Kenyon will be eligible to receive a payment up to 100 percent of base salary depending on his fulfillment of certain incentive goals for each of the years ending August 31, 1997 and August 31, 1998, and for the 16 month period ending December 31, 1999. On July 8, 1997, the NU Board authorized additional cash and stock employment retention incentives to certain of the Company's Named Executive Officers. Mr. Forsgren will receive $50,000 and, if he is still an NU system officer on July 1, 1998, an additional $100,000. Mr. Forsgren was also awarded restricted stock units representing 13,500 NU common shares that will become unrestricted if Mr. Forsgren is still an NU system officer on December 31, 1998. Mr. MacKenzie will receive $100,000 on December 31, 1998 if he is still an NU system officer on that date. Mr. Kenyon was awarded restricted stock units representing 12,200 NU common shares that are subject to the same forfeiture provisions as his earlier award. Transition and Retirement Agreement In 1992, NU entered into an agreement with Mr. Fox (the 1992 Agreement) to provide for an orderly chief executive officer succession. The agreement states that if Mr. Fox is terminated -97- without cause, he will be entitled to two years' base pay; specified employee welfare benefits; a supplemental retirement benefit equal to the difference between the target benefit he would be entitled to receive if he had reached the age of 55 on the termination date and the actual target benefit to which he is entitled as of the termination date; and a target benefit under the Supplemental Executive Retirement Plan, notwithstanding that he might not have reached age 60 on the termination date and notwithstanding other forfeiture provisions of that plan. In January 1997, NU entered into a Transition and Retirement Agreement (the Transition Agreement) with Mr. Fox to reflect his election to retire on the later of August 1, 1997 and the date his successor is elected. The Transition Agreement is intended to supersede the 1992 Agreement at the time of Mr. Fox's retirement. The Transition Agreement obligates Mr. Fox to maintain the confidentiality of NU system information during his employment and following his retirement, and not to compete with the NU system for certain periods of time in specified geographic areas. The Transition Agreement provides that Mr. Fox will be engaged as a consultant to the Board of Trustees of NU for 24 months following his retirement, with a fee of $500,000 for the first 12 months and $300,000 for the second 12 months, payable in full notwithstanding Mr. Fox's death or disability during such period or the occurrence of a change in control, as defined. Mr. Fox retired effective August 19, 1997. The Transition Agreement also provides that Mr. Fox will be entitled to a target benefit under the Supplemental Executive Retirement Plan (actuarially reduced, if applicable, to reflect payments beginning prior to age 57), and for vesting of all stock appreciation rights granted to him in the Stock Price Recovery Program. All payments and benefits under the Transition Agreement are conditioned on Mr. Fox signing a release of claims against the NU system "and all related parties" with respect to matters arising out of his employment with the NU system, and the NU system releasing Mr. Fox from all civil liability which may arise from his being or having been a Trustee or officer of NU and its subsidiaries, except for any liability which has been or may be asserted against Mr. Fox by the NU system as the result of an investigation conducted upon the demand of a shareholder or by a shareholder on behalf of the NU system. Both the 1992 Agreement and the Transition Agreement are binding on each majority-owned subsidiary of NU. Separation Agreement NUSCO entered into a Separation Agreement with Mr. Busch in August 1996 in connection with the termination of Mr. Busch's employment. The agreement provided for a severance payment of two times annual compensation, and specified supplemental employee welfare and pension benefits. It provides for confidentiality restrictions on Mr. Busch and a two year non-competition period in specified geographic locations. It includes a release by Mr. Busch of claims against the NU system and a release by the NU system of claims against Mr. Busch, except such as might be brought as the result of an investigation conducted upon the demand of a shareholder or on behalf of the NU system by shareholders. NUSCO's obligations under this agreement are binding on each majority-owned subsidiary of NU with at least fifty employees on its direct payroll. -98- The descriptions of the various agreements set forth above are for purpose of disclosure in accordance with the disclosure rules of the Commission and shall not be controlling on any party; the actual terms of the agreements themselves determine the rights and obligations of the parties. Compensation of Directors No Director of the Company receives any compensation for service as a Director. DESCRIPTION OF THE NEW BONDS General The terms of the New Bonds are identical in all material respects with the terms of the Old Bonds, except for the elimination of certain transfer restrictions, registration rights and interest rate provisions relating to the Old Bonds. The Old Bonds are, and the New Bonds will be issued under and secured by the Indenture of Mortgage and Deed of Trust dated as of May 1, 1921 between the Company and Bankers Trust Company, Trustee, as heretofore supplemented and amended, and which, as it is to be further supplemented by the Sixty-Eighth Supplemental Indenture (which is hereinafter referred to as the Sixty-Eighth Supplemental Indenture), is hereinafter called the Indenture. The summary description of the provisions of the Indenture which follows does not purport to be complete or to cover all the provisions thereof. Copies of the Indenture and the form of Sixty-Eighth Supplemental Indenture have been filed as exhibits to, or incorporated by reference in, the Registration Statement of which this Prospectus is a part (the Registration Statement) and reference is made thereto for a complete statement of the applicable provisions. Article and section references herein are to provisions of the original Indenture as heretofore amended unless otherwise indicated. The Trustee acts as a depository bank of, makes loans to, and performs other services for the Company and other companies in the NU system in the ordinary course of business. The New Bonds will be issued initially under a book-entry only system, registered in the name of Cede & Co., as registered bondholder and nominee for DTC. DTC will act as securities depositary for the New Bonds. Individual purchases of Book-Entry Interests (as herein defined) in any New Bonds will be made in book-entry form. Purchasers of Book-Entry Interests in New Bonds will not receive certificates representing their interests in such New Bonds. So long as Cede & Co., as nominee of DTC, is the bondholder, references herein to the bondholders or registered owners will mean Cede & Co., rather than the owners of Book-Entry Interests in New Bonds. See "Book-Entry; Delivery and Form" herein for certain information regarding DTC and DTC's book-entry only system. General Terms of New Bonds The New Bonds will mature on June 1, 2002 and will bear interest from June 1, 1997 at the rate of 7 3/4% per annum. Interest will be payable semiannually on June 1 and December 1, commencing December 1, 1997 at the principal office of the Trustee in New York City, to registered -99- owners at the close of business on the May 15 or November 15, as the case may be, preceding such June 1 or December 1, or if such record date is a legal holiday or a day on which banks are authorized to close in New York City, on the next preceding day which is not a legal holiday or a day on which banks are so authorized to close. The New Bonds will be issued only in the form of fully registered bonds without coupons in denominations of US$1,000 or integral multiples thereof and may be presented for exchange for a like aggregate principal amount of the same series of New Bonds of other authorized denominations and for transfer at the principal office of the Trustee in New York City without payment in either case of any charge other than for any tax or other governmental charges required to be paid by the Company. Security The Indenture constitutes a first mortgage lien (subject to liens permitted by the Indenture, including liens and encumbrances existing at the time of acquisition by the Company) on substantially all of the Company's physical property and franchises, including the Company's generating stations (but not including the Company's interest in the plants of the four regional nuclear generating companies described under "Business--Electric Operations--Nuclear Generation--General") and its transmission and distribution facilities. Subject to the provisions of the Federal Bankruptcy Code, the Indenture will also constitute a lien on after-acquired property. The Indenture also permits after-acquired property to be subject to liens prior to that of the Indenture. The security afforded by the Indenture is for the equal and ratable protection of all the Company's presently outstanding bonds and any bonds which may hereafter be issued under the Indenture, including the Bonds. (The granting clauses and (S)(S)6.04 and 6.05.) Under certain limited circumstances, the lien of the Indenture on real property in Connecticut acquired by the Company after June 3, 1985 could be subordinated to a lien in favor of the State of Connecticut pursuant to a Connecticut law (Connecticut General Statutes Section 22a-452a) providing for such a lien for reimbursement for expenses incurred in containing, removing or mitigating hazardous waste. Also, under certain limited circumstances the lien of the Indenture on real property in Massachusetts could be subordinated to a lien in favor of the Commonwealth of Massachusetts pursuant to the Massachusetts Oil and Hazardous Materials Release Prevention and Response Act, commonly known as the Massachusetts Superfund. Further, under certain limited circumstances, the lien of the Indenture on real property in New Hampshire, personal property located thereon and business revenues generated therefrom could be subordinated to a lien in favor of the State of New Hampshire pursuant to New Hampshire Revised Statutes Annotated 147B:10-b, as amended, for expenses incurred in containing or removing hazardous waste or materials, and any necessary mitigation of damages with respect to hazardous waste or materials. -100- If the Trustee exercises its rights to foreclose on the collateral, the transferral of required governmental approvals to a purchaser or new operator of the Company's generating facilities, particularly nuclear and hydro generating facilities, will require additional governmental proceedings and consequent delays. There can be no assurance that such transfers would be approved. Redemption Provisions The New Bonds will be redeemable at the option of the Company, as a whole or in part, at any time upon at least 30 days and not more than 60 days prior written notice (which notice may state that it is subject to the receipt of redemption moneys by the Trustee on or before the date fixed for redemption and which notice shall be of no effect unless such moneys are so received on or before such date) at a redemption price equal to the greater of (i) 100% of their principal amount and (ii) the sum of the present values of the remaining scheduled payments of principal and interest thereon discounted to the date of redemption on a semiannual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Yield, plus in each case accrued interest to the date of redemption (the Redemption Date). "Treasury Yield" means, with respect to any Redemption Date, the rate per annum equal to the semiannual equivalent yield to maturity of the Comparable Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date. "Comparable Treasury Issue" means the United States Treasury security selected by an Independent Investment Banker having a maturity comparable to the remaining term of the New Bonds that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the New Bonds. "Independent Investment Banker" means Morgan Stanley & Co. Incorporated or, if such firm is unwilling or unable to select the Comparable Treasury Issue, an independent investment banking institution of national standing selected by the Company and appointed by the Trustee. "Comparable Treasury Price" means, with respect to any Redemption Date (i) the average of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) on the third business day preceding such Redemption Date, as set forth in the daily statistical release (or any successor release) published by the Federal Reserve Bank of New York and designated "Composite 3:30 p.m. Quotations for U.S. Government Securities" or (ii) if such release (or any successor release) is not published or does not contain such prices on such business day, (A) the average of the Reference Treasury Quotations, or (B) if the Trustee obtains fewer than four Reference Treasury Dealer Quotations, the average of all such Quotations. "Reference Treasury Dealer Quotations" means, with respect to each Reference Treasury Dealer and any Redemption Date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its -101- principal amount) quoted in writing to the Trustee by such Reference Treasury Dealer at 5:00 p.m. on the third business day preceding such Redemption Date. "Reference Treasury Dealer" means each of Morgan Stanley & Co. Incorporated, Salomon Brothers Inc and another Primary Treasury Dealer (as defined herein) at the option of the Company, provided, however, that if any of the foregoing shall cease to be a primary U.S. Government Securities dealer in New York City (a Primary Treasury Dealer), the Company shall substitute therefor another Primary Treasury Dealer. Issuance of Additional Bonds; Earnings Coverage The Indenture permits, subject to various conditions and restrictions set forth therein, the issuance of an unlimited amount of additional first mortgage bonds. Additional bonds may be issued under the Indenture (a) to refund other bonds or certain prior lien obligations, or (b) on the basis of a certification of unbonded property additions, or (c) against the deposit of an equal amount of cash with the Trustee. The aggregate amount of first mortgage bonds (including two collateral series which secure an identical principal amount of other outstanding debt of the Company) outstanding on June 30, 1997 was approximately $1,459,000,000. Additional bonds may be issued to the extent of 60% (or such greater percent, not exceeding 66-2/3%, as may be authorized by the Commission under the Holding Company Act of unbonded property additions ((S)3.54). Additional bonds may also be issued to finance 60% (or such greater percent, not exceeding 66-2/3%, as may be authorized by the Commission under the Holding Company Act) of the bondable amount of the Company's interest in the inventory of nuclear fuel required for a nuclear generating plant ((S)3.55). Except in the case of certain refunding issues, the Company may not issue additional bonds unless its net earnings, as defined and as computed without deducting income taxes, for 12 consecutive calendar months during the period of 15 consecutive calendar months immediately preceding the first day of the month in which the application to the Trustee for authentication of additional bonds is made were at least twice the annual interest charges on all the Company's outstanding bonds, including the proposed additional bonds, and any outstanding prior lien obligations ((S)3.58). On the basis of this formula, based on the bonds and prior lien obligations outstanding as of June 30, 1997, the earnings coverage was negative and equalled (.99). The additional earnings required to bring the ratio of earnings to fixed charges to 2.0 for the twelve-month period ended June 30, 1997 would have been approximately $405,377,000. Where cash is deposited with the Trustee as a basis for the issue of bonds, it may be withdrawn against 60% (or such greater percent, not exceeding 66-2/3%, as may be authorized by the Commission under the Holding Company Act) of bondable property additions or against the deposit of bonds or prior lien obligations that would otherwise be available to be made the basis of the issue of additional bonds. Such cash may also be used to purchase or redeem bonds of any series as the Company may designate ((S)3.56). -102- As of June 30, 1997, the Company had unbonded property additions available that would support the issuance of additional bonds in the principal amount of $701,870,900, subject to the net earnings and other requirements of the Indenture. The Bonds are being issued on the basis of previously retired bonds. Other Financial Restrictions In addition to the foregoing restrictions, there are additional limitations upon the creation and/or issuance by the Company of long-term debt securities. Under certain bank and bank reimbursement agreements, lenders are not required to make additional loans or the maturity of indebtedness can be accelerated if the Company does not meet an equity ratio that requires, in effect, that the Company's common equity (as defined) be at least 27 percent of its total capitalization. On March 31, 1992, the DPUC issued a decision approving NU's acquisition of PSNH, which occurred on June 5, 1992. The DPUC's approval included several conditions designed principally to insulate the Company's customers from possible financial risks associated with NU's investment in PSNH. Among the conditions is a requirement that the Company use its best efforts to maintain the amount of common equity in the Company's capital structure (including short term debt in excess of 7 percent of total capitalization) above 36 percent. The Company must notify the DPUC if the ratio is projected to fall below 36 percent, in which case the DPUC may conduct a review of the Company's financial condition. At June 30, 1997, the Company's equity ratio (so calculated) was 34.1%. The Company did not expect to meet this condition at June 30, 1997 and notified the DPUC in accordance with the foregoing requirement. Also, in future rate cases, the Company will be required to accept a methodology for determining the Company's cost of capital for ratemaking purposes without regard to NU's cost of capital if the DPUC finds that the Company's actual debt costs are unduly influenced by effects of the PSNH acquisition. These conditions are to remain in effect until the later of May 15, 1998 and the time at which PSNH achieves investment grade ratings for its first mortgage bonds and a common equity to total capitalization ratio of at least 30 percent. Renewal and Replacement Fund If, as at the end of any year, the aggregate amount expended by the Company for property additions since December 31, 1966 is less than the "replacement fund requirement" (referred to below) for the same period, the Company is required to make up the deficit by depositing cash with the Trustee, or by depositing with the Trustee bonds or prior lien obligations which would otherwise be available as a basis for the issue of additional bonds or by certifying unbonded property additions taken at 100% of the amount certified. At the request of the Company, any cash so deposited may be used to purchase or redeem (at the applicable Special Redemption Price) bonds of such series as the Company may designate. A replacement fund deficit may thereafter be offset by expenditures in a later year in excess of the requirement for such year and thereupon the Company will be entitled, to the extent of such offset, to the return of cash, bonds or prior lien obligations deposited to make up the deficit or to reinstate as bondable any property additions certified for such purpose ((S)6.06). -103- The replacement fund requirement is computed on an annual basis, and is equal, for each year, to 2.25% of the average of the amounts carried on the Company's books for depreciable property at the beginning and end of the year ((S)1.01 (pp)). As of June 30, 1997, the Company's expenditures for property additions had exceeded the replacement fund requirement by $4,262,068,539. Withdrawal or Application of Cash Cash deposited with the Trustee pursuant to the sinking and improvement fund or replacement fund requirements may, at the Company's option, be withdrawn against a certification of unbonded property additions, or against the deposit of bonds or prior lien obligations which would otherwise be available to be made the basis of the issue of additional bonds or may be applied to the purchase or redemption (at the applicable Special Redemption Price) of bonds of such series as the Company may designate ((S)(S)6.06, 6.14 and 9.04). When the cash to be withdrawn has been deposited under the replacement fund requirement, a withdrawal equal to 100% is permitted ((S)6.06). Dividend Restrictions The Indenture contains restrictions on the payment of common stock dividends, which were included in certain Supplemental Indentures at the time of issuance of prior series of bonds. The Supplemental Indenture dated as of July 1, 1992, which contains restrictions applicable so long as any Series VV Bonds, maturing July 1, 1999, are outstanding, currently contains the most restrictive provision. Under this provision, the aggregate amount which may be declared, paid or otherwise applied by the Company as dividends or other distributions on its common stock (other than by way of stock dividends or when an equal amount of cash is received concurrently as a capital contribution or on the sale of common stock) or to the purchase or other acquisition of common stock may not exceed earned surplus (as defined, and after deducting accrued preferred stock dividends) accumulated after June 30, 1993, plus $207,000,000, plus such further amount as may be authorized by the Commission under the Holding Company Act. Pursuant to these provisions, unrestricted earned surplus at June 30, 1997 was negative, and would have amounted to approximately $72.8 million. Similar dividend restrictions are binding on the Company so long as certain prior series of the Company's bonds are outstanding. Default The Indenture provides that the following events will constitute "events of default" thereunder: failure to pay principal; failure for 90 days to pay interest; failure to perform any of the other Indenture covenants for 90 days after notice to the Company; failure to perform any covenant contained in any lien securing prior lien obligations if such default permits enforcement of the lien; and certain events in bankruptcy, insolvency or receivership ((S)10.02). The Indenture requires the Company to deliver to the Trustee an annual officers' certificate as to compliance with certain provisions of the Indenture ((S)6.16). -104- The Indenture provides that, if any event of default exists, the holders of a majority in principal amount of the bonds outstanding may, after tender to the Trustee of indemnity satisfactory to it, direct the sale of the mortgaged property ((S)10.04). Modification of the Indenture The Indenture may be supplemented or amended to convey additional property, to state indebtedness of companies merged, to add further limitations to the Indenture, to evidence a successor company, or to make such provision in regard to questions arising under the Indenture as may be necessary or desirable and not inconsistent with its terms ((S)14.01). The Indenture also permits the modification, with the consent of holders of 66-2/3% of the bonds affected, of any provision of the Indenture, except that (a) no such modification may effect a reduction of such percentage or the creation of a lien prior to or concurrent with that of the Indenture unless all bondholders consent, (b) no bondholder who refuses to consent may be deprived of his security, and (c) the Company's obligations as to the maturities, payment of principal, interest or premium and other terms of payment may not be modified unless all affected bondholders consent ((S)14.03). BOOK-ENTRY; DELIVERY AND FORM The New Bonds will be issued in fully-registered form. The description which follows of the procedures and recordkeeping with respect to beneficial ownership interests in the New Bonds, payments of principal of, and premium, if any, and interest on, the New Bonds to DTC and its Participants or Beneficial Owners, in each case as defined below, confirmation and transfer of beneficial ownership interests in the New Bonds and other related transactions by and among DTC, the DTC Participants and Beneficial Owners is based solely on information furnished by DTC. DTC is a limited-purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code, and a "clearing agency" registered pursuant to the provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds securities that its participants (Participants) deposit with DTC. DTC also facilitates the settlement among Participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book- entry changes in Participants' accounts, thereby eliminating the need for physical movement of securities certificates. Direct Participants (Direct Participants) include securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. DTC is owned by a number of its Direct Participants and by the New York Stock Exchange, Inc., the American Stock Exchange, Inc. and the National Association of Securities Dealers, Inc. Access to the DTC system is also available to others such as securities brokers and dealers, banks and trust companies that clear -105- through or maintain a custodial relationship with a Direct Participant, either directly or indirectly (Indirect Participants). The rules applicable to DTC and its Participants are on file with the SEC. Purchases of New Bonds under the DTC system must be made by or through Direct Participants, which will receive a credit for the New Bonds on DTC's records. The ownership interest of each actual purchaser of New Bonds (Beneficial Owner) is in turn to be recorded on the Direct and Indirect Participants' records. Beneficial Owners will not receive written confirmation from DTC of their purchase, but Beneficial Owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which the Beneficial Owner entered into the transaction. Transfers of ownership interests in the New Bonds are to be accomplished by entries made on the books of Participants acting on behalf of Beneficial Owners. Beneficial Owners will not receive certificates representing their ownership interests in the New Bonds, except in the event that use of the book-entry system for the New Bonds is discontinued. SO LONG AS CEDE & CO., AS NOMINEE FOR DTC, IS THE SOLE HOLDER OF THE NEW BONDS, THE TRUSTEE SHALL TREAT CEDE & CO. AS THE ONLY HOLDER OF THE NEW BONDS FOR ALL PURPOSES UNDER THE INDENTURE, INCLUDING RECEIPT OF ALL PRINCIPAL OF, AND PREMIUM, IF ANY, AND INTEREST ON SUCH NEW BONDS, RECEIPT OF NOTICES, AND VOTING AND REQUESTING OR DIRECTING THE TRUSTEE TO TAKE OR NOT TO TAKE, OR CONSENTING TO, CERTAIN ACTIONS UNDER THE INDENTURE. To facilitate subsequent transfers, all New Bonds deposited by Participants with DTC are registered in the name of DTC's partnership nominee, Cede & Co. The deposit of New Bonds with DTC and their registration into the name of Cede & Co. effect no change in beneficial ownership. DTC has no knowledge of the actual Beneficial Owners of the New Bonds; DTC's records reflect only the identity of the Direct Participants to whose accounts such New Bonds are credited, which may or may not be the Beneficial Owners. The Participants will remain responsible for keeping account of their holdings on behalf of their customers. The laws of some jurisdictions require that certain purchasers of securities take physical delivery of securities in definitive form. Such laws may impair the ability to transfer beneficial interests in any Global Security. Conveyance of notices and other communications by DTC to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time. Redemption notices, if any, shall be sent to Cede & Co. If less than all of the New Bonds within an issue are being redeemed, DTC's practice is to determine by lot the amount of the interest of each Direct Participant in such issue to be redeemed. Neither DTC nor Cede & Co. will consent or vote with respect to the New Bonds. Under its usual procedures, DTC mails an Omnibus Proxy to the Company as soon as possible after the -106- record date. The Omnibus Proxy assigns Cede & Co.'s consenting or voting rights to those Direct Participants to whose accounts the New Bonds are credited on the record date (identified in a listing attached to the Omnibus Proxy). Principal of, and premium, if any, and interest payments on the New Bonds will be made to DTC. DTC's practice is to credit Direct Participants' accounts on the applicable payment date in accordance with their respective holdings shown on DTC's records unless DTC has reason to believe that it will not receive payment on such date. Payments by Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in "street name," and will be the responsibility of such Participant and not of DTC, the Trustee or the Company, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of principal, and premium, if any, and interest to DTC is the responsibility of the Company or the Trustee, disbursement of such payments to Direct Participants shall be the responsibility of DTC and disbursement of such payments to the Beneficial Owners shall be the responsibility of Direct and Indirect Participants. DTC may discontinue providing its services as securities depositary with respect to the New Bonds at any time by giving notice to the Company or the Trustee. Under such circumstances, in the event that a successor securities depositary is not obtained, individual bond certificates are required to be printed and delivered. The Company may decide to discontinue use of the system of book-entry transfers through DTC (or a successor securities depository). In that event, individual bond certificates will be printed and delivered. The information in this section concerning DTC and DTC's book-entry system has been obtained from sources that the Company believes to be reliable (including DTC), but the Company takes no responsibility for the accuracy thereof. THE COMPANY AND THE TRUSTEE HAVE NO RESPONSIBILITY OR OBLIGATION TO THE DTC PARTICIPANTS OR THE BENEFICIAL OWNERS WITH RESPECT TO (A) THE ACCURACY OF ANY RECORDS MAINTAINED BY DTC OR ANY DTC PARTICIPANT, (B) THE PAYMENT BY ANY DTC PARTICIPANT OF ANY AMOUNT DUE TO ANY BENEFICIAL OWNER IN RESPECT OF THE PRINCIPAL OF, AND PREMIUM, IF ANY, AND INTEREST ON, THE NEW BONDS, (C) THE DELIVERY OR TIMELINESS OF DELIVERY BY DTC TO ANY DTC PARTICIPANT OR BY ANY DTC PARTICIPANT TO ANY BENEFICIAL OWNER OF ANY NOTICE WHICH IS REQUIRED OR PERMITTED UNDER THE TERMS OF THE INDENTURE TO BE GIVEN TO HOLDERS OF THE NEW BONDS, OR (D) ANY OTHER ACTION TAKEN BY DTC, OR ITS NOMINEE, CEDE & CO., AS HOLDER OF THE NEW BONDS. -107- MARKET FOR NEW BONDS The Company has been advised by the Initial Purchasers that they presently intend to make a market in the New Bonds as permitted by applicable laws and regulations. The Initial Purchasers are not obligated, however, to make a market in the New Bonds and any such market making may be discontinued at any time without prior notice at the sole discretion of the Initial Purchasers. Accordingly, no assurance can be given as to the liquidity of, or trading markets for, the New Bonds. CERTAIN FEDERAL INCOME TAX CONSIDERATIONS The following discussion, based on current law, is a general summary of the anticipated United States federal income tax consequences relevant to the exchange of Old Bonds for New Bonds and the ownership and disposition of the New Bonds by holders acquiring New Bonds pursuant to the Exchange Offer. The summary does not address all aspects of taxation that may be relevant to particular holders in light of their personal circumstances (including the effect of any foreign, state or local tax laws) or to certain types of holders subject to special treatment under federal income tax laws (such as dealers in securities, options or currencies, insurance companies, financial institutions, persons holding Bonds as part of a hedging or conversion transaction or straddle, persons whose functional currency is not the United States dollar and tax-exempt entities). The discussion of the federal income tax consequences set forth below is based upon the Internal Revenue Code of 1986, as amended (the Code), and judicial decisions and administrative interpretations thereunder, as of the date hereof, and such authorities may be repealed, revoked or modified so as to result in federal income tax consequences different from those discussed below. For purposes of the discussion set forth below, the term "Holder" includes a beneficial owner of a Bond. The discussion below is premised upon the assumption that the New Bonds are held as capital assets. The discussion below pertains only to Holders that are citizens or residents of the United States, corporations, partnerships or other entities created in or under the laws of the United States or any political subdivision thereof, estates, or trusts the administration over which a United States court can exercise primary supervision and for which one or more United States fiduciaries have the authority to control all substantial decisions, the income of which is subject to United States federal income taxation regardless of its source. EACH PROSPECTIVE HOLDER OF BONDS IS STRONGLY URGED TO CONSULT ITS OWN TAX ADVISOR WITH RESPECT TO ITS PARTICULAR TAX SITUATION, INCLUDING THE TAX EFFECTS OF ANY STATE, LOCAL, FOREIGN, OR OTHER TAX LAWS AND POSSIBLE CHANGES IN THE TAX LAWS. -108- Exchange of Bonds The exchange of Old Bonds for New Bonds pursuant to the Exchange Offer should not be treated as an exchange or other taxable event for federal income tax purposes because, under regulations promulgated by the United States Treasury Department, the New Bonds should not be considered to significantly modify the Old Bonds and thus should not differ materially in kind or extent from the Old Bonds. Rather, the New Bonds received by a Holder should be treated as a continuation of the Old Bonds in the hands of such Holder. As a result, there should be no federal income tax consequences to Holders exchanging Old Bonds for New Bonds pursuant to the Exchange Offer and a Holder should have the same adjusted basis and holding period in the New Bonds as it had in the Old Bonds immediately before the exchange. Sale or Retirement of Bonds Upon the sale, exchange or retirement of a New Bond, the Holder generally will recognize gain or loss equal to the difference between the amount realized on the sale, exchange or retirement and the Holder's adjusted tax basis in the Bond at the time thereof. Gain or loss realized on the sale, exchange or retirement of a New Bond will be capital, and will be long-term if at the time of sale, exchange or retirement the Holder has a holding period for the Bond of more than one year. The deductibility of capital losses is subject to limitations. Information Reporting and Backup Withholding Under current United States federal income tax law (i) information reporting requirements apply to "reportable payments," which include interest and principal payments made to, and the proceeds of sales by, certain noncorporate Holders of Bonds, and (ii) a Holder of Bonds may be subject to backup withholding at the rate of 31% with respect to reportable payments in respect of Bonds. Backup withholding will not apply to payments to corporations and certain other exempt recipients, such as tax- exempt organizations, which demonstrate their entitlement to exemption when required. The payor will be required to deduct and withhold (at the rate of 31%) if (i) the payee fails to furnish a taxpayer identification number (TIN) to the payor in the manner required by the Code and applicable Treasury regulations, (ii) the Internal Revenue Service notifies the payor that the TIN furnished by the payee is incorrect, (iii) there has been a "notified payee underreporting" described in Section 3406(c) of the Code, or (iv) there has been a failure of the payee to certify under penalty of perjury that the payee is not subject to withholding under 3406(d) of the Code. Amounts withheld under these rules do not constitute an additional tax and will be credited against the Holder's federal income tax liability, so long as the required information is provided to the Internal Revenue Service. The Company will report to the Holders of Bonds and to the Internal Revenue Service the amount of any "reportable payments" for each calendar year and the amount of tax withheld, if any, with respect to such payments. -109- PLAN OF DISTRIBUTION Each broker-dealer that receives New Bonds for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of such New Bonds. This Prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resale of New Bonds received in exchange for Old Bonds where such Old Bonds were acquired as a result of market-making activities or other trading activities. The Company has agreed that, for a period of 180 days after the Expiration Date, it will make this Prospectus, as amended or supplemented, available to any broker- dealer for use in connection with any such resale. The Company will not receive any proceeds from any sale of New Bonds by broker-dealers. New Bonds received by broker-dealers for their own account pursuant to the Exchange Offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the New Bonds or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such New Bonds. Any broker-dealer that resells New Bonds that were received by it for its own account pursuant to the Exchange Offer and any broker or dealer that participates in a distribution of such New Bonds may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any such resale of New Bonds any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The Letter of Transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. For a period of 180 days after the Expiration Date, the Company will promptly send additional copies of this Prospectus and any amendment or supplement to this Prospectus to any broker-dealer that requests such documents in the Letter of Transmittal. The Company has agreed to pay all expenses incident to the Exchange Offer (including the fees and disbursements of one counsel for the holders of the New Bonds) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the New Bonds (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act. LEGAL MATTERS AND EXPERTS Legal matters in connection with the issue of the New Bonds will be passed upon for the Company by Robert P. Wax, Esq., Senior Vice President, Secretary and General Counsel of the Company, or Jeffrey C. Miller, Esq., Assistant General Counsel of NUSCO. Statements of law and legal conclusions herein and in the Registration Statement pertaining to the description of the New Bonds have been reviewed by Mr. Miller. Certain statements of law and legal conclusions set forth with respect to short term borrowing authority and the earnings coverage requirement of the Indenture and preferred stock provisions of the Company, its franchises, its participation in joint projects, the laws and regulations to which it is or may be -110- subject, and litigation and legal proceedings, have been reviewed by Mr. Miller and said statements are made upon his authority as an expert. The Company's audited financial statements included in this Prospectus and schedules related thereto incorporated by reference in the Registration Statement have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports with respect thereto, which have also been included or incorporated by reference herein or therein, in reliance upon the authority of said firm as experts in accounting and auditing in giving said reports. GLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this Prospectus: COMPANIES NU....................... Northeast Utilities CL&P or the Company...... The Connecticut Light and Power Company Charter Oak or COE....... Charter Oak Energy, Inc. WMECO.................... Western Massachusetts Electric Company HWP...................... Holyoke Water Power Company NUSCO.................... Northeast Utilities Service Company NNECO.................... Northeast Nuclear Energy Company NAEC..................... North Atlantic Energy Corporation NAESCO................... North Atlantic Energy Service Corporation PSNH..................... Public Service Company of New Hampshire RRR...................... The Rocky River Realty Company Mode 1................... Mode 1 Communications, Inc. NU system................ The Northeast Utilities System CYAPC.................... Connecticut Yankee Atomic Power Company MYAPC.................... Maine Yankee Atomic Power Company VYNPC.................... Vermont Yankee Nuclear Power Corporation YAEC..................... Yankee Atomic Electric Company the Yankee Companies..... CYAPC, MYAPC, VYNPC, and YAEC GENERATING UNITS Millstone 1.............. Millstone Unit No. 1, a 660-MW nuclear generating unit completed in 1970 Millstone 2.............. Millstone Unit No. 2, an 870-MW nuclear electric generating unit completed in 1975.
-111- Millstone 3.............. Millstone Unit No. 3, a 1,154-MW nuclear electric generating unit completed in 1986 Seabrook or Seabrook l... Seabrook Unit No. 1, a 1,148-MW nuclear electric generating unit completed in 1986. Seabrook 1 went into service in 1990. REGULATORS Commission.............. Securities and Exchange Commission DOE..................... U.S. Department of Energy DPU..................... Massachusetts Department of Public Utilities DPUC.................... Connecticut Department of Public Utility Control MDEP.................... Massachusetts Department of Environmental Protection CDEP.................... Connecticut Department of Environmental Protection EPA..................... U.S. Environmental Protection Agency FERC.................... Federal Energy Regulatory Commission NHDES................... New Hampshire Department of Environmental Services NHPUC................... New Hampshire Public Utilities Commission NRC..................... Nuclear Regulatory Commission OTHER Holding Company Act..... Public Utility Holding Company Act of 1935 CAAA.................... Clean Air Act Amendments of 1990 DSM..................... Demand-Side Management Energy Act.............. Energy Policy Act of 1992 EWG..................... Exempt wholesale generator EAC..................... Energy Adjustment Clause (CL&P) FAC..................... Fuel Adjustment Clause (CL&P) FPPAC................... Fuel and purchased power adjustment clause (PSNH) GUAC.................... Generation Utilization Adjustment Clause (CL&P) IRM..................... Integrated resource management kWh...................... Kilowatt-hour Money Pool............... A system for the pooling of funds established by certain of the NU system companies to provide a more effective use of their cash
-112- resources and to reduce outside short-term borrowings. MW....................... Megawatt NBFT..................... Niantic Bay Fuel Trust, lessor of nuclear fuel used by CL&P and WMECO NEPOOL................... New England Power Pool NUGs..................... Nonutility generators NUG&T.................... Northeast Utilities Generation and Transmission agreement QF....................... Qualifying facility
-113- THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Public Accountants............. F-2 Consolidated Balance Sheets as of December 31, 1996 and 1995 and June 30, 1997 (unaudited)...................... F-3 - F-4 Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994 and the six months ended June 30, 1997 (unaudited) and 1996 (unaudited)................... F-5 Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994 and the six months ended June 30, 1997 (unaudited) and 1996 (unaudited)................................... F-6 Consolidated Statements of Common Stockholder's Equity for the years ended December 31, 1996, 1995 and 1994 and the six months ended June 30, 1997 (unaudited).......................... F-7 F-1 Report Of Independent Public Accountants To the Board of Directors of The Connecticut Light and Power Company: We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) and subsidiaries as of December 31, 1996 and 1995, and the related consolidated statements of income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 1996. 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 The Connecticut Light and Power Company and subsidiaries as of December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 21, 1997 F-2 THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
June 30, 1997 At December 31, ---------- -------------------------- (Unaudited) 1996 1995 ---------- ---- ---- (Thousands of Dollars) ASSETS - ------ Utility Plant, at original cost: Electric............................................ $6,348,007 $6,283,736 $6,147,961 Less: Accumulated provision for depreciation (Note 1F)..................... 2,776,198 2,665,519 2,418,557 ---------- ----------- ---------- 3,571,809 3,618,217 3,729,404 Construction work in progress....................... 92,073 95,873 103,026 Nuclear fuel, net................................... 134,453 133,050 138,203 ---------- ----------- ---------- Total net utility plant........................... 3,798,335 3,847,140 3,970,633 ---------- ----------- ---------- Other Property and Investments: Nuclear decommissioning trusts, at market........... 322,967 296,960 238,023 Investments in regional nuclear generating companies, at equity (Note 1E)..................... 59,532 56,925 54,624 Other, at cost...................................... 39,884 16,565 16,241 ---------- ----------- ---------- 422,383 370,450 308,888 ---------- ----------- ---------- Current Assets: Cash................................................ 263 404 337 Notes receivable from affiliated companies.......... 56,000 109,050 -- Receivables, net.................................... 211,087 226,112 231,574 Accounts receivable from affiliated companies....... 3,615 3,481 3,069 Taxes receivable.................................... 57,986 40,134 -- Accrued utility revenues............................ 83,008 78,451 91,157 Fuel, materials, and supplies, at average cost...... 84,367 79,937 68,482 Recoverable energy costs, net--current portion...... 24,473 25,436 78,108 Prepayments and other............................... 80,059 63,344 42,894 ---------- ----------- ---------- 600,858 626,349 515,621 ---------- ----------- ---------- Deferred Charges: Regulatory assets (Note 1H)......................... 1,236,418 1,370,781 1,225,280 Unamortized debt expense............................ 19,938 17,033 14,977 Other............................................... 19,399 12,283 10,232 ---------- ----------- ---------- 1,275,755 1,400,097 1,250,489 ---------- ----------- ---------- ---------- ----------- ---------- Total Assets.................................... $6,097,331 $6,244,036 $6,045,631 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. F-3 THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
June 30, 1997 At December 31, ---------- ---------------------------------- (Unaudited) 1996 1995 ---------- ---- ---- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock--$10 par value. Authorized 24,500,000 shares; outstanding 12,222,930 shares ....... $ 122,229 $ 122,229 $ 122,229 Capital surplus, paid in................................ 640,495 639,657 637,981 Retained earnings....................................... 467,290 551,410 785,476 ---------- ----------- ----------- Total common stockholder's equity.............. 1,230,014 1,313,296 1,545,686 Preferred stock not subject to mandatory redemption..... 116,200 116,200 116,200 Preferred stock subject to mandatory redemption......... 155,000 155,000 155,000 Long-term debt.......................................... 2,018,462 1,834,405 1,812,646 ---------- ----------- ----------- Total capitalization........................... 3,519,676 3,418,901 3,629,532 ---------- ----------- ----------- Minority Interest in Consolidated Subsidiary (Note 13)... 100,000 100,000 100,000 ---------- ----------- ----------- Obligations Under Capital Leases (Note 2)................. 144,583 143,347 108,408 ---------- ----------- ----------- Current Liabilities: Notes payable to banks.................................. 100,000 -- 41,500 Notes payable to affiliated companies................... -- -- 10,250 Long-term debt--current portion......................... 25,615 204,116 9,372 Obligations under capital leases--current portion (Note 2)....................................... 12,407 12,361 63,856 Accounts payable........................................ 127,563 160,945 110,798 Accounts payable to affiliated companies................ 54,060 78,481 44,677 Accrued taxes........................................... 24,786 28,707 52,268 Accrued interest........................................ 29,695 31,513 30,854 Nuclear compliance (Note 11B)........................... 51,740 50,500 -- Other................................................... 26,107 34,433 20,027 ---------- ----------- ----------- 451,973 601,056 383,602 ---------- ----------- ----------- Deferred Credits: Accumulated deferred income taxes (Note 1I)............. 1,334,954 1,365,641 1,486,873 Accumulated deferred investment tax credits............. 131,397 135,080 142,447 Deferred contractual obligations (Note 3)............... 271,372 305,627 65,847 Other................................................... 143,376 174,384 128,922 ---------- ----------- ----------- 1,881,099 1,980,732 1,824,089 ---------- ----------- ----------- Commitments and Contingencies (Note 11) Total Capitalization and Liabilities........... $6,097,331 $6,244,036 $6,045,631 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. F-4 THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
June 30, For the Years Ended December 31, ------------------------- --------------------------------------- 1997 1996 1996 1995 1994 --------- ---------- ---------- ---------- ---------- (Unaudited) (Thousands of Dollars) Operating Revenues.................................... $1,199,749 $1,202,354 $2,397,460 $2,387,069 $2,328,052 ---------- ---------- ---------- ---------- ---------- Operating Expenses: Operation -- Fuel, purchased and net interchange power........ 479,261 360,847 830,924 608,600 568,394 Other............................................ 355,336 386,570 778,329 614,382 593,851 Maintenance......................................... 168,374 132,168 300,005 192,607 207,003 Depreciation........................................ 118,969 124,500 247,109 242,496 231,155 Amortization of regulatory assets, net.............. 31,361 3,975 57,432 54,217 77,384 Federal and state income taxes (Note 8)............. (28,806) 29,484 (20,174) 178,346 190,249 Taxes other than income taxes....................... 85,693 89,636 174,062 172,395 173,068 ---------- ---------- ---------- ---------- ---------- Total operating expenses...................... 1,210,188 1,127,180 2,367,687 2,063,043 2,041,104 ---------- ---------- ---------- ---------- ---------- Operating (Loss) Income............................... (10,439) 75,174 29,773 324,026 286,948 ---------- ---------- ---------- ---------- ---------- Other Income: Deferred nuclear plants return--other funds......... 51 907 1,268 4,683 13,373 Equity in earnings of regional nuclear generating companies.............................. 3,149 3,793 6,619 6,545 7,453 Other, net.......................................... 8,055 8,139 19,442 9,902 5,136 Minority interest in income of subsidiary (Note 13).............................. (4,650) (4,650) (9,300) (8,732) -- Income taxes........................................ 414 (396) 160 (2,978) 4,248 ---------- ---------- ---------- ---------- ---------- Other income, net............................. 7,019 7,793 18,189 9,420 30,210 ---------- ---------- ---------- ---------- ---------- (Loss) Income before interest charges......... (3,420) 82,967 47,962 333,446 317,158 ---------- ---------- ---------- ---------- ---------- Interest Charges: Interest on long-term debt.......................... 63,882 60,131 127,198 124,350 119,927 Other interest...................................... 3,286 771 1,147 5,596 6,378 Deferred nuclear plants return--borrowed funds...... (68) (86) (146) (1,716) (7,435) ---------- ---------- ---------- ---------- ---------- Interest charges, net......................... 67,100 60,816 128,199 128,230 118,870 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Net (Loss) Income..................................... $ (70,520) $ 22,151 $ (80,237) $ 205,216 $ 198,288 ========== ========== ========== ========== ==========
The accompanying notes are an integral part of these financial statements. F-5 THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, For the Years Ended December 31, --------------------- ---------------------------------- 1997 1996 1996 1995 1994 --------------------- ---------------------------------- (Thousands of Dollars) Operating Activities: (Unaudited) Net (Loss) Income .............................................. $ (70,520) $ 22,151 $ (80,237) $205,216 $198,288 Adjustments to reconcile to net cash from operating activities: Depreciation.................................................. 118,969 124,500 247,109 242,496 231,155 Deferred income taxes and investment tax credits, net......... (10,465) (46,362) (60,773) 49,520 37,664 Deferred nuclear plants return, net of amortization........... (119) 6,272 7,746 95,559 82,651 Deferred demand-side-management costs, net of amortization.... 37,329 23,306 26,941 (937) (4,691) Recoverable energy costs, net of amortization................. 11,522 (2,044) (35,567) (16,169) 3,975 Deferred cogeneration costs, net of amortization.............. 16,388 6,193 25,957 (55,341) (36,821) Nuclear compliance, net....................................... 1,240 38,447 50,500 -- -- Deferred nuclear refueling outage, net of amortization........ (22,667) 24,797 45,643 (20,712) (4,653) Other sources of cash......................................... 19,899 88,202 75,552 86,956 47,791 Other uses of cash............................................ (27,065) (45,096) (23,862) (53,745) (4,697) Changes in working capital: Receivables and accrued utility revenues...................... 10,334 31,484 (22,378) (33,032) 45,386 Fuel, materials, and supplies................................. (4,430) (15,146) (11,455) (4,479) (3,756) Accounts payable.............................................. (57,803) (5,940) 83,951 9,605 (24,167) Accrued taxes................................................. (3,921) (38,199) (23,561) 25,855 (9,726) Other working capital (excludes cash)......................... (44,711) 2,154 (5,385) (1,869) (18,403) --------- -------- --------- --------- -------- Net cash flows (used for) from operating activities............... (26,020) 214,719 300,181 528,923 539,996 --------- -------- --------- --------- -------- Financing Activities: Issuance of Monthly Income Preferred Securities................ -- -- -- 100,000 -- Net increase (decrease) in short-term debt...................... 100,000 (51,750) (51,750) (127,000) 82,500 Issuance of long-term debt...................................... 200,000 222,000 222,000 -- 535,000 Reacquisitions and retirements of long-term debt................ (193,288) (9,479) (14,329) (10,866) (774,020) Reacquisitions and retirements of preferred stock............... -- (125,000) -- Cash dividends on preferred stock............................... (7,611) (7,611) (15,221) (21,185) (23,895) Cash dividends on common stock.................................. (5,989) (103,528) (138,608) (164,154) (159,388) --------- -------- --------- --------- -------- Net cash flows from (used for) financing activities............... 93,112 49,632 2,092 (348,205) (339,803) --------- -------- --------- --------- -------- Investment Activities: Investment in plant: Electric utility plant........................................ (74,494) (56,363) (140,086) (131,858) (149,889) Nuclear fuel.................................................. (669) 2,255 553 (1,543) (20,905) --------- -------- --------- --------- -------- Net cash flows used for investments in plant.................... (75,163) (54,108) (139,533) (133,401) (170,794) NU System Money Pool............................................ 53,050 (187,950) (109,050) -- -- Investments in nuclear decommissioning trusts................... (19,194) (22,858) (50,998) (47,826) (28,129) Other investment activities, net................................ (25,926) 437 (2,625) 581 (1,565) --------- -------- --------- --------- -------- Net cash flows used for investments............................... (67,233) (264,479) (302,206) (180,646) (200,488) --------- -------- --------- --------- -------- Net (Decrease) Increase In Cash For The Period.................... (141) (128) 67 72 (295) Cash - beginning of period........................................ 404 337 337 265 560 --------- -------- --------- --------- -------- Cash - end of period.............................................. $ 263 $ 209 $ 404 $ 337 $ 265 ========= ======== ========= ========= ======== Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amounts capitalized............................ $ 114,458 $ 117,074 $115,120 ========= ========= ======== Income taxes............................................. $ 77,790 $ 137,706 $161,513 ========= ========= ======== Increase in obligations: Niantic Bay Fuel Trust and other capital leases................ $ 2,855 $ 33,537 $ 52,353 ========= ========= ========
See accompanying notes to consolidated financial statements. F-6 THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Capital Retained Common Surplus, Earnings Stock Paid In (a) Total ---------- ---------- ---------- ----------- (Thousands of Dollars) Balance at January 1, 1994........................... $ 122,229 $ 630,271 $ 750,719 $ 1,503,219 Net income for 1994.............................. 198,288 198,288 Cash dividends on preferred stock................ (23,895) (23,895) Cash dividends on common stock................... (159,388) (159,388) Capital stock expenses, net...................... 1,846 1,846 ---------- ---------- ---------- ----------- Balance at December 31, 1994......................... 122,229 632,117 765,724 1,520,070 Net income for 1995.............................. 205,216 205,216 Cash dividends on preferred stock................ (21,185) (21,185) Cash dividends on common stock................... (164,154) (164,154) Loss on the retirement of preferred stock........ (125) (125) Capital stock expenses, net...................... 5,864 5,864 ---------- ---------- ---------- ----------- Balance at December 31, 1995......................... 122,229 637,981 785,476 1,545,686 Net loss for 1996................................ (80,237) (80,237) Cash dividends on preferred stock................ (15,221) (15,221) Cash dividends on common stock................... (138,608) (138,608) Capital stock expenses, net...................... 1,676 1,676 ---------- ---------- ---------- ----------- Balance at December 31, 1996......................... 122,229 639,657 551,410 1,313,296 (Unaudited) Net loss for six months ended June 30, 1997.................................. (70,520) (70,520) Cash dividends on preferred stock................ (7,611) (7,611) Cash dividends on common stock................... (5,989) (5,989) Capital stock expenses, net...................... 838 838 ---------- ---------- ---------- ----------- Balance at June 30, 1997 (unaudited)................. $ 122,229 $ 640,495 $ 467,290 $ 1,230,014 ========== ========== ========== ===========
(a) The company has dividend restrictions imposed by its long-term debt agreements. At June 30, 1997 and December 31, 1996, these restrictions totaled approximately $540 million. The accompanying notes are an integral part of these financial statements. F-7 [THIS PAGE INTENTIONALLY LEFT BLANK] ILB F-8 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. About The Connecticut Light and Power Company The Connecticut Light and Power Company and Subsidiaries (the company or CL&P), Western Massachusetts Electric Company (WMECO), Holyoke Water Power Company (HWP), Public Service Company of New Hampshire (PSNH), and North Atlantic Energy Corporation (NAEC) are the operating subsidiaries comprising the Northeast Utilities system (the system) and are wholly owned by Northeast Utilities (NU). The system furnishes franchised retail electric service in Connecticut, New Hampshire, and western Massachusetts through CL&P, PSNH, WMECO, and HWP. A fifth subsidiary, NAEC, sells all of its entitlement to the capacity and output of the Seabrook nuclear power plant to PSNH. In addition to its franchised retail electric service, the system furnishes firm and other wholesale electric services to various municipalities and other utilities and, on a pilot basis pursuant to state regulatory experiments, provides off-system retail electric service. The system serves about 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. Other wholly owned subsidiaries of NU provide support services for the system companies and in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing, and other services to the system companies. Northeast Nuclear Energy Company (NNECO) acts as agent for the system companies in operating the Millstone nuclear generating facilities. North Atlantic Energy Service Corporation (NAESCO) acts as agent for CL&P and NAEC and has operational responsibilities for the Seabrook nuclear generating facility. B. Presentation General: The consolidated financial statements of CL&P include the accounts of all wholly owned subsidiaries. Significant 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. F-9 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) Certain reclassifications of prior periods' data have been made to conform with the current period's presentation. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity, and are subject to approval by various federal and state regulatory agencies. Unaudited Interim Financial Statements: In the opinion of the company, the accompanying interim financial statements contain all adjustments necessary to present fairly the financial position as of June 30, 1997, the results of operations for the six-month periods ended June 30, 1997 and 1996, and the statements of cash flows for the six-month periods ended June 30, 1997 and 1996. All adjustments are of a normal, recurring, nature except those described below in Note 11B. The results of operations for the six-month periods ended June 30, 1997 and 1996 are not necessarily indicative of the results expected for a full year. Certain notes to financial statements have not been updated for the interim periods because there have been no significant events. C. Public Utility Regulation 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 it and its subsidiaries, including the company, are subject to the provisions of the 1935 Act. Arrangements among the 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 company is subject to further regulation for rates, accounting and other matters by the FERC and/or the Connecticut Department of Public Utility Control (DPUC). D. New Accounting Standards The Financial Accounting Standards Board (FASB) has issued Statement of Financial Accounting Standards (SFAS) 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," which established accounting standards for evaluating and recording asset impairment. The company adopted SFAS 121 as of January 1, 1996. See Note 1H, "Summary of Significant Accounting Policies - Regulatory Accounting and Assets" for further information on the regulatory impacts of the company's adoption of SFAS 121. See Note 10, "Sale of Customer Receivables and Accrued Utility Revenues," and Note 11C, "Commitments and Contingencies - F-10 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) Environmental Matters," for information on newly issued accounting and reporting standards related to those specific areas. The FASB issued two new accounting standards in February 1997: SFAS No. 128, "Earnings per Share" and SFAS 129, "Disclosure of Information about Capital Structure." SFAS 128 and SFAS 129 will be effective for 1997 year-end reporting. FASB issued two new accounting standards during June 1997: SFAS No. 130, "Reporting Comprehensive Income" and SFAS 131, "Disclosures about Segments of an Enterprise and Related Information." SFAS 130 establishes standards for the reporting and disclosure of comprehensive income. SFAS 131 determines the standards for reporting and disclosing qualitative and quantitative information about a company's operating segments. Both SFAS 130 and SFAS 131 will be effective in 1998. Management believes that the implementation of SFAS 128, SFAS 129, SFAS 130, and SFAS 131 will not have a material impact on CL&P's financial position or its results of operations. E. Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: CL&P owns common stock of four regional nuclear generating companies (Yankee companies). The Yankee companies, with the company's ownership interests are:
------------------------------------------------------------ Connecticut Yankee Atomic Power Company (a) (CYAPC).. 34.5% Yankee Atomic Electric Company (a) (YAEC)............ 24.5 Maine Yankee Atomic Power Company (a)(MYAPC)......... 12.0 Vermont Yankee Nuclear Power Corporation (VYNPC)..... 9.5 ------------------------------------------------------------
(a) YAEC's, CYAPC's, and MYAPC's nuclear power plants were shut down permanently on February 26, 1992, December 4, 1996, and August 6, 1997, respectively. CL&P's investments in the Yankee companies are accounted for on the equity basis due to the company's ability to exercise significant influence over their operating and financial policies. F-11 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) CL&P's investments in the Yankee companies at December 31, 1996 are:
------------------------------------------------------------------ (Thousands of Dollars) Connecticut Yankee Atomic Power Company.... $36,954 Yankee Atomic Electric Company............. 5,854 Maine Yankee Atomic Power Company.......... 8,956 Vermont Yankee Nuclear Power Corporation... 5,161 ------- $56,925 -------------------------------------------------------------------
The electricity produced by VY is committed substantially on the basis of ownership interests and is billed pursuant to contractual agreement. Under ownership agreements with the Yankee companies, CL&P may be asked to provide direct or indirect financial support for one or more of the companies. For more information on these agreements, see Note 11F, "Commitments and Contingencies - Long-Term Contractual Arrangements." For more information on the Yankee companies, see Note 3, "Nuclear Decommissioning" and Note 11B, "Commitments and Contingencies - Nuclear Performance." Millstone 1: CL&P has an 81.0 percent joint ownership interest in Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of December 31, 1996 and 1995, plant-in-service included approximately $384.5 million and $372.6 million, respectively, and the accumulated provision for depreciation included approximately $159.4 million and $148.4 million, respectively, for CL&P's share of Millstone 1. CL&P's share of Millstone 1 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. Millstone 2: CL&P has an 81.0 percent joint ownership interest in Millstone 2, an 870-MW nuclear generating unit. As of December 31, 1996 and 1995, plant-in-service included approximately $690.4 million and $684.5 million, respectively, and the accumulated provision for depreciation included approximately $224.1 million and $198.5 million, respectively, for CL&P's share of Millstone 2. CL&P's share of Millstone 2 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. Millstone 3: CL&P has a 52.93 percent joint ownership interest in Millstone 3, a 1,154-MW nuclear generating unit. As of December 31, 1996 and 1995, plant-in-service included approximately $1.9 billion, and the accumulated provision for depreciation included approximately $504.1 million and $455.1 million, respectively, for CL&P's share of Millstone 3. CL&P's F-12 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) share of Millstone 3 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. For more information regarding the Millstone units, see Note 11B, "Commitments and Contingencies - Nuclear Performance." Seabrook 1: CL&P has a 4.06 percent joint ownership interest in Seabrook 1, a 1,148-MW nuclear generating unit. As of December 31, 1996 and 1995, plant-in-service included approximately $173.7 million and $173.3 million, respectively, and the accumulated provision for depreciation included approximately $29.7 million and $24.8 million, respectively, for CL&P's share of Seabrook 1. CL&P's share of Seabrook 1 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. F. Depreciation The provision for depreciation is calculated using the straight-line method based on estimated remaining lives of depreciable utility plant- in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency. 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 plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 4.0 percent in 1996 and 1995, and 3.9 percent in 1994. See Note 3, "Nuclear Decommissioning," for information on nuclear plant decommissioning. CL&P's nonnuclear generating facilities have limited service lives. Plant may be retired in place or dismantled based upon expected future needs, the economics of the closure and environmental concerns. The costs of closure and removal are incremental costs and, for financial reporting purposes, are accrued over the life of the asset as part of depreciation. At December 31, 1996, the accumulated provision for depreciation included approximately $43 million accrued for the cost of removal, net of salvage for nonnuclear generation property. G. Revenues Other than revenues under fixed-rate agreements negotiated with certain wholesale, industrial and commercial customers and limited pilot retail access programs, utility revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a F-13 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) formal proceeding before the appropriate regulatory commission. At the end of each accounting period, CL&P accrues an estimate for the amount of energy delivered but unbilled. H. Regulatory Accounting and Assets The accounting policies of CL&P and the accompanying consolidated financial statements conform to generally accepted accounting principles applicable to rate regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, "Accounting for the Effects of Certain Types of Regulation." Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered through future revenues. Through their actions, regulators may also reduce or eliminate the value of an asset, or create a liability. If any portion of the company's operations were no longer subject to the provisions of SFAS 71, as a result of a change in the cost-of-service based regulatory structure or the effects of competition, the company would be required to write off related regulatory assets and liabilities. Recently, the SEC has questioned the ability of certain utilities to remain on SFAS 71 in light of state legislation regarding the transition to retail competition. The industry expects guidance on this issue from FASB's Emerging Issues Task Force in the near future. While there are restructuring initiatives pending in the NU system companies' respective jurisdictions, CL&P is not yet subject to a transition plan. The company continues to believe that its use of regulatory accounting remains appropriate. SFAS 121 requires the evaluation of long-lived assets, including regulatory assets, for impairment when certain events occur or when conditions exist that indicate the carrying amounts of assets may not be recoverable. SFAS 121 requires that any long-lived assets which are no longer probable of recovery through future revenues be revalued based on estimated future cash flows. If the revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. The implementation of SFAS 121 did not have a material impact on the company's financial position or results of operations as of June 30, 1997 and December 31, 1996. Management continues to believe that it is probable that the company will recover its investments in long-lived assets through future revenues. This conclusion may change in the future as competitive factors influence wholesale and retail pricing in the electric utility industry or if the cost-of-service based regulatory structure were to change. F-14 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) The components of CL&P's regulatory assets are as follows:
- -------------------------------------------------------------------- June 30, December 31, 1997 1996 1995 - -------------------------------------------------------------------- (Unaudited) (Thousands of Dollars) Income taxes, net (Note 1I)...... $ 722,085 $ 753,390 $ 863,521 Recoverable energy costs, net (Note 1J)................... 87,341 97,900 9,662 Deferred demand side management costs (Note 1K)................. 52,800 90,129 117,070 Cogeneration costs (Note 1L)..... 49,817 66,205 92,162 Unrecovered contractual obligations (Note 3)............ 263,874 300,627 65,847 Other............................ 60,501 62,530 77,018 ---------- ---------- ---------- $1,236,418 $1,370,781 $1,225,280 ========== ========== ==========
For more information on the company's regulatory environment and the potential impacts of restructuring, see Note 11A, "Commitments and Contingencies - Restructuring" and Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). 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 ratemaking treatment of the applicable regulatory commissions. The adoption of SFAS 109, "Accounting for Income Taxes," in 1993 increased the company's net deferred tax obligation. As it is probable that the increase in deferred tax liabilities will be recovered from customers through rates, CL&P established a regulatory asset. See Note 8, "Income Tax Expense" for the components of income tax expense. F-15 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, which give rise to the accumulated deferred tax obligation is as follows:
- -------------------------------------------------------------------- June 30, December 31, 1997 1996 1995 - -------------------------------------------------------------------- (Unaudited) (Thousands of Dollars) Accelerated depreciation and other plant- related differences...... $1,026,636 $1,032,857 $1,074,242 Regulatory assets - income tax gross up...... 304,383 313,420 347,673 Other..................... 3,935 19,364 64,958 ---------- ---------- ---------- $1,334,954 $1,365,641 $1,486,873 ========== ========== ==========
J. Recoverable Energy Costs Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (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 is currently recovering these costs through rates. As of June 30, 1997 and December 31, 1996, the company's total D&D deferrals were approximately $49.3 million and $49.2 million, respectively. During 1996, retail electric rates included a fuel adjustment clause (FAC) under which fossil fuel prices above or below base-rate levels are charged or credited to customers. In addition, CL&P also utilized a generation utilization adjustment clause (GUAC), which deferred the effect on fuel costs caused by variations from a specified composite nuclear generation capacity factor embedded in base rates. At June 30, 1997 and December 31, 1996, CL&P's net recoverable energy costs, excluding current net recoverable energy costs, were approximately $87.3 million and $97.9 million, respectively, which includes the D&D assessment. For additional information, see Note 11B, "Commitments and Contingencies - Nuclear Performance." On October 8, 1996, the DPUC issued an order establishing an Energy Adjustment Clause (EAC) which became effective F-16 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) January 1, 1997. The EAC has replaced CL&P's existing FAC and GUAC. For further information regarding the EAC, see the MD&A. K. Demand Side Management (DSM) CL&P's DSM costs are recovered in base rates through a Conservation Adjustment Mechanism (CAM). The $90.1 million of costs on CL&P's books as of December 31, 1996, will be fully recovered by 2000. During November, 1996, CL&P filed its 1997 DSM program and forecasted CAM for 1997 with the DPUC. The filing proposes expenditures of $36 million in 1997, with recovery over 1.9 years and a zero CAM rate. In April 1997, the DPUC approved 1997 expenditures of $36 million, a zero CAM rate for 1997 and recovery of the 1997 expenditures over 1.7 years beginning January 1, 1998. L. Cogeneration Costs Beginning on July 1, 1996, the deferred cogeneration balance of approximately $86 million is being amortized over a five year period. An additional $9 million of amortization is being applied to the deferred balance in 1997, as required under a settlement agreement which CL&P reached with the DPUC. CL&P will continue to apply any savings associated with the renegotiation of a certain contract with a cogeneration facility to the deferred balance. Under current expectations, CL&P expects complete amortization of the deferred balance by December 31, 1998. M. Spent Nuclear Fuel Disposal Costs Under the Nuclear Waste Policy Act of 1982, CL&P must pay the United States Department of Energy (DOE) for 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), payment must be made prior to the first delivery of spent fuel to the DOE. The DOE was originally scheduled to begin accepting delivery of spent fuel in 1998. However, delays in identifying a permanent storage site have continually postponed plans for the DOE's long-term storage and disposal site. The DOE's current estimate for an available site is 2010. Until such payment is made, the outstanding balance will continue to accrue interest at the three-month Treasury Bill Yield Rate. At December 31, 1996, fees due to the DOE for the disposal of prior-period fuel were approximately $158.0 million, including interest costs of $91.5 million. At June 30, 1997, fees due to the DOE for the disposal of spent nuclear fuel were approximately $162.1 million, including F-17 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) interest costs of $95.6 million. As of June 30, 1997, all fees had been collected through rates. N. Fuel Price Management The company utilizes fuel-price management instruments to manage well defined fuel price risks. Amounts receivable or payable under fuel-price management instruments are recognized in income when realized. Any material unrealized gains or losses on fuel-price management instruments will be deferred until realized. For further information, see Note 12, "Fuel Price Management." 2. LEASES CL&P and WMECO finance up to $450 million of nuclear fuel for Millstone 1 and 2 and their respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement. 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. CL&P has also entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, gas turbines, nuclear control room simulators and office space. The provisions of these lease agreements generally provide for renewal options. The following rental payments have been charged to expense:
Year Capital Leases Operating Leases ---- -------------- ---------------- 1996.......... $17,993,000 $22,032,000 1995.......... 56,307,000 23,793,000 1994.......... 60,975,000 24,192,000
Interest included in capital lease rental payments was $10,144,000 in 1996, $10,587,000 in 1995, and $10,228,000 in 1994. Substantially all of the capital lease rental payments were made pursuant to the nuclear fuel lease agreement. Future minimum lease payments under the nuclear fuel capital lease cannot be reasonably estimated on an annual basis due to variations in the usage of nuclear fuel. F-18 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) 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, 1996 are:
Year Capital Leases Operating Leases ---- -------------- ---------------- (Thousands of Dollars) 1997...................... $ 2,800 $ 26,100 1998...................... 2,900 21,500 1999...................... 2,900 19,900 2000...................... 2,900 18,800 2001...................... 3,000 13,700 After 2001................ 66,400 46,400 -------- -------- Future minimum lease payments................ 80,900 $146,400 ======== Less amount representing interest............... 61,900 -------- Present value of future minimum lease payments for other than nuclear fuel............ 19,000 Present value of future nuclear fuel lease payments................ 136,800 -------- Total..................... $155,800 ========
It is possible that certain operating lease payments related to NUSCO leases will be accelerated from future years into 1997. See Note 11G, "The Rocky River Realty Company - Obligations" for additional information. On June 21, 1996, CL&P entered into an operating lease with a third party to acquire the use of four turbine generators having an installed cost of approximately $70 million. During the first quarter of 1997, CL&P determined that it would not be in compliance with financial coverage tests required under the lease agreement. CL&P has reached an agreement with the lessors for a resolution of this matter. Management believes that the terms and conditions of this agreement will not have a material adverse impact on the company's financial position or results of operations. F-19 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) 3. NUCLEAR DECOMMISSIONING CL&P's nuclear power plants have service lives that are expected to end during the years 2010 through 2026. Upon retirement, these units must be decommissioned. Decommissioning studies prepared in 1996 concluded that complete and immediate dismantlement at retirement continues to be the most viable and economic method of decommissioning the three Millstone units and Seabrook 1. Decommissioning studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology and inflation. The estimated cost of decommissioning CL&P's ownership share of Millstone 1 and 2, in year-end 1996 dollars, is $316.0 million and $279.0 million, respectively. CL&P's ownership share of the estimated cost of decommissioning Millstone 3 and Seabrook 1 in year-end 1996 dollars, is $244.9 million and $18.3 million, respectively. The Millstone units and Seabrook 1 decommissioning costs will be increased annually by their respective escalation rates. Nuclear decommissioning costs are accrued over the expected service life of the units and are included in depreciation expense on the Consolidated Statements of Income. Nuclear decommissioning costs amounted to $37.8 million in 1996, $30.5 million in 1995, and $25.6 million in 1994. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Consolidated Balance Sheets. At June 30, 1997 and December 31, 1996, the balance in the accumulated reserve for decommissioning amounted to $361.1 million and $329.1 million, respectively. CL&P has established external decommissioning trusts through a trustee for its portion of the costs of decommissioning Millstone 1, 2, and 3. CL&P's portion of the cost of decommissioning Seabrook 1 is paid to an independent decommissioning financing fund managed by the state of New Hampshire. Funding of the estimated decommissioning costs assume levelized collections for the Millstone units and escalated collections for Seabrook 1 and after- tax earnings on the Millstone and Seabrook decommissioning funds of 5.8 percent and 6.5 percent, respectively. As of June 30, 1997 and December 31, 1996, CL&P has collected, through rates, $259.4 million and $240.8 million, respectively, towards the future decommissioning costs of its share of the Millstone units, of which $221.7 million and $209.1 million, respectively, have been transferred to external decommissioning trusts. As of June 30, 1997 and December 31, 1996, CL&P has paid approximately $2.6 million and $2.4 million, respectively, into Seabrook 1's decommissioning financing fund. Earnings on the decommissioning trusts and financing fund increase the decommissioning trust balance and the accumulated reserve for decommissioning. Unrealized gains and losses associated with the F-20 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) decommissioning trusts and financing fund also impact the balance of the trusts and financing fund and the accumulated reserve for decommissioning. 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 attempts to recover sufficient amounts through its allowed rates to cover its expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by regulatory agencies is reflected in CL&P's rates. Based on present estimates and assuming its nuclear units operate to the end of their respective license periods, CL&P expects that the decommissioning trusts and financing fund will be substantially funded when the units are retired from service. VYNPC: VYNPC owns a single nuclear generating unit (VY). VY has a service life that is expected to end in 2012. The estimated cost, in year-end 1996 dollars, of decommissioning CL&P's ownership share of the unit owned and operated by VYNPC is $34.8 million. Under the terms of the contract with VYNPC, the shareholders-sponsors are responsible for their proportionate share of the operating costs of the unit, including decommissioning. The nuclear decommissioning costs of VY is included as part of the cost of power purchased by CL&P. MYAPC: MYAPC owns a single nuclear generating unit (MY) with a service life that was expected to end in 2008. On August 6, 1997, the board of directors of MYAPC voted unanimously to cease permanently the production of power at its nuclear plant. The system companies had relied on MY for approximately two percent of their capacity. For further information on MY, see Note 11B, "Commitments and Contingencies - Nuclear Performance." CYAPC: On December 4, 1996, the board of directors of CYAPC voted unanimously to cease permanently the production of power at its nuclear plant (CY). The system companies relied on CY for approximately three percent of their capacity. CYAPC has undertaken a number of regulatory filings intended to implement the decommissioning and the recovery of remaining assets of CY. During late December, 1996, CYAPC filed an amendment to its power contracts to clarify the obligations of its purchasing utilities following the decision to cease power production. At December 31, 1996, the estimated obligation, including decommissioning, amounted to $762.8 million of which CL&P's share was approximately $263.2 million. F-21 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) On February 27, 1997, FERC approved an order for hearing which, among other things, accepted CYAPC's contract amendments for filing and suspended the new rates for a nominal period. The new rates became effective March 1, 1997, subject to refund. At June 30, 1997, CL&P's share of the CY unrecovered contractual obligation, which also has been recorded as a regulatory asset, was $235.0 million. YAEC: YAEC is in the process of decommissioning its nuclear facility. At December 31, 1996, the estimated remaining costs, including decommissioning, amounted to $173.3 million of which CL&P's share was approximately $42.5 million. At June 30, 1997, CL&P's share of the YAEC unrecovered contractual obligation which also has been recorded as a regulatory asset, was $28.8 million. Management expects that CL&P will continue to be allowed to recover the costs associated with CY and YAEC from its customers. Accordingly, CL&P has recognized these costs as regulatory assets, with corresponding obligations, on its Consolidated Balance Sheets. Proposed Accounting: The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry, including the company, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating units in the financial statements. In response to these questions, FASB agreed to review the accounting for removal costs, including decommissioning, and issued a proposed statement entitled "Accounting for Liabilities Related to Closure or Removal of Long-Lived Assets," in February, 1996. If current electric utility industry accounting practices for decommissioning are changed in accordance with the proposed statement: (1) annual provisions for decommissioning could increase, (2) the estimated cost for decommissioning could be recorded as a liability with an offset to plant rather than as part of accumulated depreciation, and (3) trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense. 4. SHORT-TERM DEBT Limits: The amount of short-term borrowings that may be incurred by CL&P is subject to periodic approval by either the SEC under the 1935 Act or by its state regulator. In addition, the charter of CL&P contains provisions restricting the amount of short-term debt borrowings. Under the SEC and/or charter restrictions, the company was authorized, as of January 1, 1997, to incur short-term borrowings up to a maximum of $375 million. F-22 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) Credit Agreements: In November, 1996, NU entered into a three-year revolving credit agreement (New Credit Agreement) with a group of 12 banks. Under the terms of the New Credit Agreement, NU, CL&P and WMECO will be able to borrow up to $150 million, $313.75 million, and $150 million, respectively. The overall limit for all of the borrowing system companies under the entire New Credit Agreement is $313.75 million. The system companies are currently obligated to pay a facility fee of .50 percent per annum of each bank's total commitment under the new credit facility which will expire November 21, 1999. At December 31, 1996 there were $27.5 million in borrowings under this agreement, all of which were borrowed by other system companies. At June 30, 1997, there were no borrowings under this agreement. Access to the New Credit Agreement is contingent upon certain financial tests being met. NU is currently renegotiating these restrictions so that the financial impacts of the current nuclear outages do not impact the ability to access these facilities. Through February 21, 1997, CL&P and WMECO have satisfied all financial covenants required under their respective borrowing facilities, but NU needed and obtained a limited waiver of an interest coverage covenant that had to be satisfied for NU to borrow under the New Credit Agreement. On May 30, 1997, the First Amendment and Waiver became effective, replacing an interim written agreement and amending the New Credit Agreement. This closing permitted $313.75 million of credit to remain available to CL&P and WMECO through securing their borrowings with first mortgage bonds. Interest coverage and common equity ratios were revised to enable the companies to meet certain financial tests. CL&P will be able to borrow up to $225 million on the strength of bonds it has provided as collateral for borrowings under this agreement. WMECO will be able to borrow up to $90 million on the basis of bonds it has provided as collateral and the NU parent company, which as a holding company cannot issue first mortgage bonds, will be able to borrow up to $50 million if CL&P, WMECO, and NU consolidated financial statements meet certain interest coverage tests for two consecutive quarters. In addition to the New Credit Agreement, NU, CL&P, WMECO, HWP, NNECO and The Rocky River Realty Company (RRR) have various revolving credit lines through separate bilateral credit agreements. Under the remaining three- year portion of the facility, four banks maintain commitments to the respective system companies totaling $56.25 million. NU, CL&P and WMECO may borrow up to the aggregate $56.25 million, whereas HWP, NNECO and RRR may borrow up to their short-term debt limit of $5 million, $50 million and $22 million, respectively. Under the terms of the agreement, the system companies are obligated to pay a facility fee of .15 percent per annum of each bank's total commitment F-23 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) under the three-year portion of the facility. These commitments will expire December 3, 1998. At December 31, 1996 and 1995, there were $11.3 million and $42.5 million in borrowings, respectively, under the facility, of which CL&P had no borrowings in 1996 and $10 million in borrowings in 1995. At June 30, 1997, CL&P had no borrowings under the facility. Under both credit facilities above, the company may borrow funds on a short-term revolving basis under the remaining portion of its agreement, using either fixed-rate loans or standby loans. Fixed rates are set using competitive bidding. Standby loans are based upon several alternative variable rates. The weighted average annual interest rate on CL&P's notes payable to banks outstanding at December 31, 1995 was 6.0 percent. Maturities of CL&P's short-term debt obligations are for periods of three months or less. Money Pool: Certain subsidiaries of NU, including CL&P, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the system, and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate. However, borrowings based on loans from NU parent bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At June 30, 1997 and December 31, 1996, CL&P had no borrowings outstanding from the Pool. At December 31, 1995, CL&P had $10.3 million of borrowings outstanding from the Pool. The interest rate on borrowings from the Pool on December 31, 1995 was 4.7 percent. For further information on short-term debt see the MD&A. F-24 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) 5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION Details of preferred stock not subject to mandatory redemption are:
Shares December 31, Outstanding 1996 at 6/30/97 June 30, December 31, Redemption and 1997 ------------------------------- Description Price 12/31/96 (Unaudited) 1996 1995 1994 - ----------------------------- ------------ ----------- ----------- --------- --------- --------- (Thousands of Dollars) $1.90 Series of 1947........ $52.50 163,912 $ 8,196 $ 8,196 $ 8,196 $ 8,196 $2.00 Series of 1947........ 54.00 336,088 16,804 16,804 16,804 16,804 $2.04 Series of 1949........ 52.00 100,000 5,000 5,000 5,000 5,000 $2.06 Series E of 1954...... 51.00 200,000 10,000 10,000 10,000 10,000 $2.09 Series F of 1955...... 51.00 100,000 5,000 5,000 5,000 5,000 $2.20 Series of 1949........ 52.50 200,000 10,000 10,000 10,000 10,000 $3.24 Series G of 1968...... 51.84 300,000 15,000 15,000 15,000 15,000 3.90% Series of 1949........ 50.50 160,000 8,000 8,000 8,000 8,000 4.50% Series of 1956........ 50.75 104,000 5,200 5,200 5,200 5,200 4.50% Series of 1963........ 50.50 160,000 8,000 8,000 8,000 8,000 4.96% Series of 1958........ 50.50 100,000 5,000 5,000 5,000 5,000 5.28% Series of 1967........ 51.43 200,000 10,000 10,000 10,000 10,000 6.56% Series of 1968........ 51.44 200,000 10,000 10,000 10,000 10,000 1989 Adjustable Rate DARTS.. -- -- -- -- -- 50,000 Total preferred stock not subject to mandatory redemption $116,200 $116,200 $116,200 $166,200 ======== ======== ======== ========
All or any part of each outstanding series of such preferred stock may be redeemed by the company at any time at established redemption prices plus accrued dividend to the date of redemption. F-25 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) 6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock subject to mandatory redemption are:
Shares December 31, Outstanding 1996 at 6/30/97 June 30, December 31, Redemption and 1997 ---------------------------- Description Price* 12/31/96 (Unaudited) 1996 1995 1994 - ------------------------ ------------ ---------- ---------- -------- -------- -------- (Thousands of Dollars) 9.00% Series of 1989... -- -- $ -- $ -- $ -- $ 75,000 7.23% Series of 1992... $52.41 1,500,000 75,000 75,000 75,000 75,000 5.30% Series of 1993... $51.00 1,600,000 80,000 80,000 80,000 80,000 -------- ------- -------- -------- $155,000 $155,000 $155,000 $230,000 ======== ======== ======== ======== Less preferred stock to be redeemed within one year........ -- -- -- 3,750 Total preferred stock subject to mandatory redemption............. $155,000 $155,000 $155,000 $226,250 ======== ======== ======== ========
*Each of these series is subject to certain refunding limitations for the first five years after they were issued. Redemption prices reduce in future years. The following table details redemption and sinking fund activity for preferred stock subject to mandatory redemption:
Minimum Annual Shares Reacquired Sinking-Fund ---------------------------- Series Requirement 1996 1995 1994 - -------------------------- -------------- --------- --------- -------- (Thousand of Dollars) 9.00% Series of 1989 $ -- -- 3,000,000 -- 7.23% Series of 1992 (1) 3,750 -- -- -- 5.30% Series of 1993 (2) 16,000 -- -- --
(1) Sinking fund requirements commence September 1, 1998. (2) Sinking fund requirements commence October 1, 1999. The minimum sinking-fund provisions of the series subject to mandatory redemption, for the years 1998 through 2001, aggregate approximately $3.8 million in 1998, and $19.8 million in 1999, 2000 and 2001. There were no minimum sinking-fund provisions in 1997. In case of default on sinking- fund payments or the payment of dividends, 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 the company is in arrears in the payment of dividends on any outstanding shares of preferred stock, the company would be prohibited from redemption or F-26 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) purchase of less than all of the preferred stock outstanding. All or part of each of the series named above may be redeemed by the company at any time at established redemption prices plus accrued dividends to the date of redemption, subject to certain refunding limitations. 7. LONG-TERM DEBT Details of long-term debt outstanding are:
December 31, June 30, ---------------------- 1997 (Unaudited) 1996 1995 - --------------------------------------------------------------------------- (Thousands of Dollars) First Mortgage Bonds: 7 5/8% Series UU due 1997..... $ -- $ 193,288 $ 197,245 6 1/2% Series T due 1998..... 20,000 20,000 20,000 7 1/4% Series VV due 1999..... 99,000 99,000 100,000 5 1/2% 1994 Series A due 1999. 140,000 140,000 140,000 5 3/4% Series XX due 2000..... 200,000 200,000 200,000 7 7/8% 1996 Series A due 2001. 160,000 160,000 -- 7 3/4% 1997 Series B due 2002. 200,000 -- -- 6 1/8% 1994 Series B due 2004. 140,000 140,000 140,000 7 3/8% Series TT due 2019..... 20,000 20,000 20,000 7 1/2% Series YY due 2023..... 100,000 100,000 100,000 8 1/2% Series C due 2024...... 115,000 115,000 115,000 7 7/8% Series D due 2024...... 140,000 140,000 140,000 7 3/8% Series ZZ due 2025..... 125,000 125,000 125,000 ---------- ---------- ---------- Total First Mortgage Bonds 1,459,000 1,452,288 1,297,245 Pollution Control Notes: Variable rate, due 2016-2022. 46,400 46,400 46,400 Tax exempt, due 2028-2031.... 377,500 377,500 315,500 Fees and interest due for spent fuel disposal costs (Note 1M).............. 162,116 157,968 149,978 Other......................... 5,691 10,915 20,286 Less: Amounts due within one year..................... 25,615 204,116 9,372 Unamortized premium and discount, net................ (6,630) (6,550) (7,391) ---------- ---------- ---------- Long-term debt, net.......... $2,018,462 $1,834,405 $1,812,646 ========== ========== ==========
F-27 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) Long-term debt and cash sinking-fund requirements on debt outstanding at December 31, 1996 for the years 1997 through 2001 are approximately $204.1 million, $20.0 million, $239.0 million, $200.0 million, and $160.0 million, respectively. In addition, there are annual one-percent sinking- and improvement-fund requirements, currently amounting to $14.5 million for 1997, $12.6 million for 1998, $12.4 million for 1999, $10.0 million for 2000, and $8.0 million for 2001. Such sinking- and improvement-fund requirements may be satisfied by the deposit of cash or bonds or by certification of property additions. All or any part of each outstanding series of first mortgage bonds may be redeemed by the company at any time at established redemption prices plus accrued interest to the date of redemption, except certain series which are subject to certain refunding limitations during their respective initial five-year redemption periods. Essentially all of the company's utility plant is subject to the lien of its first mortgage bond indenture. As of December 31, 1996 and 1995, the company has secured $315.5 million of pollution control notes with second mortgage liens on Millstone 1, junior to the lien of its first mortgage bond indenture. The average effective interest rate on the variable-rate pollution control notes ranged from 3.4 percent to 3.6 percent for 1996 and from 3.8 percent to 4.0 percent for 1995. On January 23, 1997, the letter of credit associated with CL&P's $62 million tax-exempt PCRBs, issued on May 21, 1996, was replaced with a bond insurance and liquidity facility secured by First Mortgage Bonds. The bonds were originally backed by a five-year letter of credit and secured by a second mortgage on CL&P's interest in Millstone 1. On June 26, 1997, CL&P issued $200 million of First and Refunding Mortgage Bonds, 1997 Series B (CL&P 1997 Series B Bonds). The CL&P 1997 Series B Bonds bear interest at an annual rate of 7.75 percent and will mature on June 1, 2002. Downgrade Events: On April 28, 1997, Moody's Investors Service (Moody's) announced that it was downgrading both CL&P's and WMECO's first mortgage bonds from their "Baa3" rating to a "Ba1" rating. This rating change has placed CL&P's and WMECO's first mortgage bonds in Moody's below investment grade category. On May 22, 1997, Standard and Poor's Corporation (S&P) announced that it was downgrading both CL&P's and WMECO's corporate credit and its senior secured debt from their rating of "BBB-" to "BB+." This rating change has placed CL&P's and WMECO's first mortgage bonds in S&P'S below investment grade category. F-28 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) 8. INCOME TAX EXPENSE The components of the federal and state income tax provisions charged to operations are:
----------------------------------------------------------------------------------------------------------------------- Six Months Ended For the Years Ended June 30, December 31, 1997 1996 1996 1995 1994 ----------------------------------------------------------------------------------------------------------------------- (Unaudited) (Thousands of Dollars) Current income taxes: Federal.............................................. $(17,769) $ 56,713 $ 30,650 $ 93,906 $108,371 State................................................ (986) 19,529 9,789 37,898 39,966 -------- -------- -------- -------- -------- Total current........................................ (18,755) 76,242 40,439 131,804 148,337 -------- -------- -------- -------- -------- Deferred income taxes, net: Federal............................................... (4,687) (31,270) (38,680) 52,075 44,180 State................................................. (2,095) (11,409) (14,726) 5,085 842 -------- -------- -------- -------- -------- Total deferred........................................ (6,782) (42,679) (53,406) 57,160 45,022 Investment tax credits, net............................. (3,683) (3,683) (7,367) (7,640) (7,358) -------- -------- -------- -------- -------- Total income tax expense.............................. $(29,220) $ 29,880 $(20,334) $181,324 $186,001 ======== ======== ======== ======== ========
The components of total income tax expense are classified as follows: Income taxes charged to operating expenses.................................... $(28,806) $ 29,484 $(20,174) $178,346 $190,249 Other income taxes...................................... (414) 396 (160) 2,978 (4,248) -------- -------- -------- -------- -------- Total income tax expense................................ $(29,220) $ 29,880 $(20,334) $181,324 $186,001 ======== ======== ======== ======== ========
Deferred income taxes are comprised of the tax effects of temporary differences as follows:
----------------------------------------------------------------------------------------------------------------------- Six Months Ended For the Years Ended June 30, December 31, 1997 1996 1996 1995 1994 ----------------------------------------------------------------------------------------------------------------------- (Unaudited) (Thousands of Dollars) Depreciation, leased nuclear fuel, settlement credits and disposal costs........................................ $ 6,266 $ 962 $ 3,981 $ 44,278 $ 38,874 Energy adjustment clauses............................... (13,870) (3,665) (1,654) 23,302 14,465 Demand-side management.................................. (12,148) (12,970) (17,099) 1,310 203 Nuclear plant deferrals................................. 10,489 (10,929) (18,861) (8,055) (20,452) Bond redemptions........................................ (681) (938) (1,789) (2,255) 6,826 Contractual settlements................................. 873 1,304 2,513 (9,496) 109 Nuclear compliance reserves............................. (517) (16,085) (21,131) - - Other................................................... 2,806 (358) 634 8,076 4,997 -------- -------- -------- -------- -------- Deferred income taxes, net.............................. $ (6,782) $(42,679) $(53,406) $ 57,160 $ 45,022 ======== ======== ======== ======== ========
F-29 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) A reconciliation between income tax expense and the expected tax expense at the applicable statutory rate is as follows:
---------------------------------------------------------------------------------------------------------- June 30, December 31, 1997 1996 1996 1995 1994 ---------------------------------------------------------------------------------------------------------- (Unaudited) (Thousands of Dollars) Expected federal income tax at 35 percent of pretax income..... $(35,149) $18,211 $(35,931) $135,289 $134,501 Tax effect of differences: State income taxes, net of federal benefit............... (2,002) 5,278 (3,209) 27,939 26,526 Depreciation.................... 9,868 11,741 21,313 23,517 18,602 Deferred nuclear plants return.. (18) (318) (444) (1,639) (4,681) Amortization of regulatory assets............. 2,437 1,396 8,601 20,218 19,755 Property tax.................... - - - (159) 5,286 Investment tax credit amortization.................. (3,683) (3,683) (7,367) (7,640) (7,358) Adjustment for prior years' taxes......................... - - - (10,442) (2,706) Other, net...................... (673) (2,745) (3,297) (5,759) (3,924) -------- ------- -------- -------- -------- Total income tax expense.......... $(29,220) $29,880 $(20,334) $181,324 $186,001 ======== ======= ======== ======== ========
9. EMPLOYEE BENEFITS A. Pension Benefits The company participates in a uniform noncontributory defined benefit retirement plan covering all regular system employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. The company's direct portion of the system's pension income, part of which was credited to utility plant, approximated $8.8 million in 1996, $10.4 million in 1995 and $2.3 million in 1994. The company's pension costs for 1996, 1995, and 1994 included approximately $2.8 million, $0.1 million, and $4.8 million, respectively, related to workforce reduction programs. Currently, the company funds annually an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code. Pension costs are determined using market-related values of pension assets. Pension assets are invested primarily in domestic and international equity securities and bonds. F-30 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) The components of net pension cost for CL&P are:
----------------------------------------------------------------------------------------- For the Years Ended December 31, 1996 1995 1994 ----------------------------------------------------------------------------------------- (Thousands of Dollars) Service cost............................................. $ 11,896 $ 7,543 $ 13,072 Interest cost............................................ 37,226 37,110 36,103 Return on plan assets.................................... (103,248) (138,582) 1,020 Net amortization......................................... 45,300 83,516 (52,536) --------- --------- -------- Net pension income....................................... $ (8,826) $ (10,413) $ (2,341) ========= ========= ========
For calculating pension cost, the following assumptions were used:
------------------------------------------------------------------------------------------- For the Years Ended December 31, 1996 1995 1994 ------------------------------------------------------------------------------------------- Discount rate............................................ 7.50% 8.25% 7.75% Expected long-term rate of return......................................... 8.75 8.50 8.50 Compensation/progression rate................................................... 4.75 5.00 4.75 -------------------------------------------------------------------------------------------
The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets:
---------------------------------------------------------------- At December 31, 1996 1995 ---------------------------------------------------------------- (Thousands of Dollars) Accumulated benefit obligation, including vested benefits at December 31, 1996 and 1995 of $405,340,000 and $404,540,000, respectively....................... $ 434,473 $ 432,987 ========= ========= Projected benefit obligation......... $ 514,989 $ 515,121 Market value of plan assets.......... 736,448 668,929 --------- --------- Market value in excess of projected benefit obligation................. 221,459 153,808 Unrecognized transition amount....... (7,365) (8,285) Unrecognized prior service costs..... 3,818 1,293 Unrecognized net gain................ (198,088) (135,817) --------- --------- Prepaid pension asset................ $ 19,824 $ 10,999 ========= =========
F-31 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) The following actuarial assumptions were used in calculating the plan's year-end funded status:
---------------------------------------------- At December 31, 1996 1995 ---------------------------------------------- Discount rate.................. 7.75% 7.50% Compensation/progression rate.. 4.75 4.75 ----------------------------------------------
B. Postretirement Benefits Other Than Pensions The company provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (referred to as SFAS 106 benefits). These benefits are available for employees retiring from the company who have met specified service requirements. For current employees and certain retirees, the total SFAS 106 benefit is limited to two times the 1993 per-retiree health care costs. The SFAS 106 obligation has been calculated based on this assumption. CL&P's direct portion of SFAS 106 benefits, part of which were deferred or charged to utility plant, approximated $17.9 million in 1996, $20.7 million in 1995 and $22.3 million in 1994. During 1996 and 1995, the company funded SFAS 106 postretirement costs through external trusts. The company is funding, on an annual basis, amounts that have been rate-recovered and which also are tax deductible under the Internal Revenue Code. The trust assets are invested primarily in equity securities and bonds. The components of health care and life insurance cost are:
----------------------------------------------------------- For the Years Ended December 31, 1996 1995 1994 ----------------------------------------------------------- (Thousands of Dollars) Service cost.................. $ 2,270 $ 2,248 $ 2,371 Interest cost................. 10,211 11,510 12,157 Return on plan assets......... (2,904) (1,015) 2 Amortization of unrecognized transition obligation....... 7,344 7,344 7,344 Other amortization, net....... 956 602 430 ------- ------- ------- Net health care and life insurance costs............. $17,877 $20,689 $22,304 ======= ======= =======
F-32 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) For calculating SFAS 106 benefit costs, the following assumptions were used:
------------------------------------------------------------------------------- For the Years Ended December 31, 1996 1995 1994 ------------------------------------------------------------------------------- Discount rate................................... 7.50% 8.00% 7.75% Long-term rate of return - Health assets, net of tax..................... 5.25 5.00 5.00 Life assets................................... 8.75 8.50 8.50
The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets:
------------------------------------------------------------------------------------- At December 31, 1996 1995 ------------------------------------------------------------------------------------- (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees.................................................. $109,299 $ 126,624 Fully eligible active employees......................... 165 198 Active employees not eligible to retire............................................. 27,913 29,798 -------- --------- Total accumulated postretirement benefit obligation....................................... 137,377 156,620 Market value of plan assets................................ 38,783 11,378 -------- --------- Accumulated postretirement benefit obligation in excess of plan assets............................................... (98,594) (145,242) Unrecognized transition amount............................. 117,506 124,850 Unrecognized net (gain)/loss............................... (18,912) 1,260 -------- --------- Accrued postretirement benefit liability................................................. $ 0 $ (19,132) ======== ========= -------------------------------------------------------------------------------------
The following actuarial assumptions were used in calculating the plan's year-end funded status:
----------------------------------------------- At December 31, 1996 1995 ----------------------------------------------- Discount rate.................... 7.75% 7.50% Health care cost trend rate (a).. 7.23 8.40
F-33 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 4.91 percent by 2001. The effect of increasing the assumed health care cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1996, by $7.6 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $600,000. The trust holding the health plan assets is subject to federal income taxes at a 39.6 percent tax rate. CL&P is currently recovering SFAS 106 costs. 10. SALE OF CUSTOMER RECEIVABLES AND ACCRUED UTILITY REVENUES CL&P has entered into an agreement to sell up to $200 million of eligible customer receivables and accrued utility revenues. The eligible receivables and accrued utility revenues are sold with limited recourse. The agreement was entered into during July, 1996 and will expire in five years. The company has retained collection responsibilities for receivables which have been sold under the agreement. The agreement provides for a loss reserve determined by a formula which reflects credit exposure. There were no accounts receivable sold under the agreement as of December 31, 1996. As of June 30, 1997, CL&P had sold approximately $100 million of its accounts receivable under the agreement. The FASB issued SFAS 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," in June, 1996. SFAS 125 became effective on January 1, 1997, and establishes, in part, criteria for concluding whether a transfer of financial assets in exchange for consideration should be accounted for as a sale or as a secured borrowing. At present, CL&P is required to record the sales of its customer accounts receivable as secured short-term borrowings. CL&P is currently in the process of restructuring its accounts receivable sales agreement so that CL&P may treat this transaction as a sale as permitted under SFAS 125. Management believes that the adoption of SFAS 125 will not have a material impact on the company's financial position or results of operations. 11. COMMITMENTS AND CONTINGENCIES A. Restructuring Although CL&P continues to operate under cost-of-service based regulation, various restructuring initiatives in its jurisdiction have created uncertainty with respect to future rates and the recovery of strandable investments and certain future costs such as purchase power obligations. Strandable investments are regulatory assets or other assets that would F-34 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) not be economical in a competitive environment. Management is unable to predict the ultimate outcome of restructuring initiatives; however, it believes that it is entitled to full recovery of its prudently incurred costs, including regulatory assets and strandable investments based on the general nature of public utility cost of service regulation. For further information on restructuring, see the MD&A. B. Nuclear Performance Millstone: The three Millstone units are managed by NNECO. Millstone 1, 2, and 3 have been out of service since November 4, 1995, February 21, 1996 and March 30, 1996, respectively, and are on the Nuclear Regulatory Commission's (NRC) watch list. Management has restructured its nuclear organization and is currently implementing comprehensive plans to restart the units. Millstone 3 has been designated by NU management as the lead unit for restart. Millstone 2 remains on a schedule to be ready for restart shortly after Millstone 3. To provide the resources and focus for Millstone 3, the pace of work on the restart of Millstone 1 was reduced until late in 1997 at which time the full work effort will be resumed. Management believes that Millstone 3 will be ready for restart by the end of the third quarter of 1997, Millstone 2 in the fourth quarter of 1997 and Millstone 1 in the first quarter of 1998. Because of the need for completion of independent inspections and reviews and for the NRC to complete its processes before the NRC Commissioners can vote on permitting a unit to restart, the actual beginning of operations is expected to take several months beyond the time when a unit is declared ready for restart. The NRC's internal schedules at present indicate that a meeting of the Commissioners to act upon a Millstone 3 restart request could occur by mid-December if NU, the independent review teams and NRC staff concur that the unit can return to operation by that time. A similar schedule indicates a mid-March meeting of the Commissioners to act upon a Millstone 2 restart request. Management hopes that Millstone 3 can begin operating by the end of 1997. The company is currently incurring substantial costs, including replacement power costs, while the three Millstone units are not operating. Management does not expect to recover a substantial portion of these costs. CL&P expensed approximately $143 million of incremental nonfuel nuclear operation and maintenance costs (O&M) in 1996, including a reserve of $50 million against 1997 expenditures. At year-end management estimated that CL&P will expense approximately $309 million of nonfuel O&M costs in 1997. F-35 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) Based on a recent review of work efforts and budgets, management believes that the overall 1997 nuclear spending levels, which include both nuclear O&M expenditures and associated support services and capital expenditures, will be slightly higher than previously estimated. The 1997 projected nuclear O&M expenditures are expected to increase, while 1997 projected capital expenditures are expected to decrease. CL&P's share of nonfuel O&M costs for Millstone to be expensed in 1997 is now projected to be approximately $353 million compared to $309 million previously estimated. The 1997 projection includes $12 million of restart costs identified to date which is expected to be incurred in 1998 and is net of $50 million of Millstone costs reserved in 1996. CL&P's share of 1997 projected capital expenditures for Millstone is expected to decrease from the $48 million previously estimated to $35 million. For the six months ended June 30, 1997, CL&P's share of nonfuel O&M costs expensed for Millstone totaled $211 million. The actual expenditures include $40 million reserved for future 1997 restart costs and $12 million reserved for 1998 restart costs, and is net of $50 million of spending against the reserve established in 1996. The reserve balance at June 30, 1997, was approximately $52 million. Nonfuel O&M costs have been and will continue to be absorbed by CL&P without adjustment to its current rates. Management will continue to evaluate the costs to be incurred for the remainder of 1997 and in 1998 to determine whether adjustments to the existing reserves are required. As discussed above, management cannot predict when the NRC will allow any of the Millstone units to return to service and thus cannot estimate the total replacement power costs the company will ultimately incur. Replacement power costs incurred by CL&P attributable to the Millstone outages averaged approximately $23 million per month during the first six months of 1997, and are projected to average approximately $21 million per month for the remainder of 1997. Based on current estimates of expenditures and restart dates, management believes the system has sufficient resources to fund the restoration of the Millstone units and related replacement power costs. CL&P Prudence Investigation: In response to motions filed by various parties and intervenors, the DPUC on June 27, 1997 orally granted summary judgment in CL&P's nuclear outage investigation docket, disallowing recovery of costs associated with the ongoing outages at Millstone. On July 30, 1997, the DPUC issued a purported written decision in the same case, which disallowed recovery of an estimated F-36 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) $600 million of replacement power costs related to the Millstone outages, and found that CL&P had waived recovery of an additional $360 million of incremental O&M. The written decision, like the oral decision, recognized CL&P's right to seek recovery, in a future rate proceeding, of $40 million related to reliability enhancements. CL&P has appealed the DPUC's decision. CL&P has not requested cost recovery at this time and has said that it will not seek recovery for a substantial portion of these costs and will not request any cost recovery until the units are returned to operation. Any requests for recovery would include only costs for projects CL&P would have undertaken under normal operating conditions or that provide long-term value for CL&P customers. CL&P does not expect the DPUC's decision to have a material financial impact on projected 1997 results. MY: On August 6, 1997, the board of directors of MYAPC voted unanimously to cease permanently the production of power at its nuclear generating facility. MYAPC has begun to prepare the regulatory filings intended to implement the decommissioning and the recovery of remaining assets of its nuclear facility. During the latter part of 1997, MYAPC plans to file an amendment to its power contracts to clarify the obligations of its purchasing utilities following the decision to cease power production. MYAPC is currently updating its decommissioning cost estimates. These estimates are expected to be completed during the third quarter of 1997. At this time, the company is unable to estimate its obligation to MYAPC. Under the terms of the contracts with MYAPC, the shareholders-sponsor companies, including CL&P, are responsible for their proportionate share of the costs of the unit, including decommissioning. Management expects that CL&P will be allowed to recover these costs from its customers. Litigation: CL&P and WMECO, through NNECO, operate Millstone 3 at cost, and without profit, under a Sharing Agreement that obligates them to utilize good utility practice and requires the joint owners to share the risk of employee negligence and other risks of operation and maintenance pro-rata in accordance with their ownership shares. The Sharing Agreement also provides that CL&P and WMECO would only be liable for damages to the non-NU owners for a deliberate violation of the agreement pursuant to authorized corporate action. On August 7, 1997, the non-NU owners of Millstone 3 filed demands for arbitration with CL&P and WMECO as well as lawsuits in Massachusetts Superior Court against Northeast Utilities and its current and former trustees. The non-NU owners raise a number of contract, tort and statutory claims, arising out of F-37 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) the operation of Millstone 3. The arbitrations and lawsuits seek to recover compensatory damages, punitive damages, treble damages and attorneys' fees. Owners representing approximately two-thirds of the non- NU interests in Millstone 3 have claimed compensatory damages in excess of $200 million. In addition, one of the lawsuits seeks to restrain NU from disposing of its shares of the stock of WMECO and Holyoke Water Power Company, pending the outcome of the lawsuit. The NU companies believe there is no legal basis for the claims and intend to defend against them vigorously. C. Environmental Matters CL&P is subject to regulation by federal, state and local authorities with respect to air and water quality, the handling and disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. CL&P has an active environmental auditing and training program and believes that it is in substantial compliance with current environmental laws and regulations. Environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations, and other facilities. Changing environmental requirements could also require extensive and costly modifications to CL&P's existing generating units and transmission and distribution systems, and could raise operating costs significantly. As a result, CL&P may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation and transmission of electricity and the storage, transportation and disposal of by-products and wastes. CL&P may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. The cumulative long-term cost impact of increasingly stringent environmental requirements cannot accurately be estimated. CL&P has recorded a liability based upon currently available information for what it believes are its estimated environmental remediation costs for waste disposal sites. In most cases, additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation and the possible effects of technological changes. At December 31, 1996, the net liability recorded by CL&P for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $7.5 million, which management has determined to be the most F-38 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) probable amount within the range of $7.5 million to $14.0 million. On October 10, 1996, the American Institute of Certified Public Accountants issued Statement of Position 96-1, "Environmental Remediation Liabilities" (SOP). The principal objective of the SOP is to improve the manner in which existing authoritative accounting literature is applied by entities to specific situations of recognizing, measuring and disclosing environmental remediation liabilities. The SOP became effective January 1, 1997. The adoption of the SOP resulted in a $400 thousand increase to CL&P's environmental reserve. At June 30, 1997, CL&P's net liability recorded for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $7.8 million, which management has determined to be the most probable amount within the range of $7.8 million to $13.5 million. CL&P cannot estimate the potential liability for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws and regulatory practices, management does not believe the matters disclosed above will have a material effect on CL&P's financial position or future results of operations. D. Nuclear Insurance Contingencies 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 company could be assessed in proportion to its ownership interest in each nuclear unit up to $75.5 million, not to exceed $10.0 million per nuclear unit in any one year. Based on its ownership interest in Millstone 1, 2, and 3 and in Seabrook 1, CL&P's maximum liability, including any additional potential assessments, would be $173.6 million per incident. In addition, through power purchase contracts with MYAPC, VYNPC and CYAPC, CL&P would be responsible for up to an additional $44.4 million per incident. Payments for CL&P's ownership interest in nuclear generating facilities would be limited to a maximum of $27.5 million per incident per year. Insurance has been purchased to cover the primary cost of repair, replacement or decontamination of utility property resulting from insured occurrences. CL&P is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessment against CL&P with respect to losses arising during the current policy year was approximately $10.4 million under the primary F-39 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) property insurance program at December 31, 1996. Based on the most recent renewal, the maximum potential assessment against CL&P with respect to losses arising during the current policy year is approximately $11.2 million under the primary property insurance program at June 30, 1997. Insurance has been purchased to cover 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 resulting from insured occurrences. CL&P is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessments against the company with respect to losses arising during current policy years are approximately $9 million under the replacement power policies and $20.4 million under the excess property damage, decontamination and decommissioning policies. The cost of a nuclear incident could exceed available insurance proceeds. Insurance has been purchased aggregating $200 million on a industry basis for coverage of worker claims. All participating reactor operators insured under this coverage are subject to retrospective assessments of $3 million per reactor. The maximum potential assessment against CL&P with respect to losses arising during the current policy period is approximately $8.9 million. E. Construction Program The construction program is subject to periodic review and revision by management. CL&P currently forecasts construction expenditures of approximately $842 million for the years 1997-2001, including $165 million for 1997. In addition, the company estimates that nuclear fuel requirements, including nuclear fuel financed through the NBFT, will be approximately $238.4 million for the years 1997-2001, including $12.2 million for 1997. See Note 2, "Leases," for additional information about the financing of nuclear fuel. As a result of the most recent capital program review, management has decreased the construction program forecast for 1997 expenditures from $165 million to $148 million. F. Long-Term Contractual Arrangements Yankee Companies: CL&P, along with PSNH and WMECO, has relied on MY and VY for approximately three percent of their capacity under long-term contracts. Under the terms of their agreements, the system companies pay their ownership (or entitlement) shares of costs, which include depreciation, O&M expenses, taxes, the estimated cost of decommissioning and a return on invested capital. These costs are recorded as F-40 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) purchased power expense and recovered through the company's rates. CL&P's total cost of purchases under contracts with the Yankee companies, excluding YAEC, amounted to $96.4 million in 1996, $105.8 million in 1995, and $102.1 million in 1994. See Note 1E, "Summary of Significant Accounting Policies-Investments and Jointly Owned Electric Utility Plant," and Note 3, "Nuclear Decommissioning," and Note 11B "Nuclear Performance" for more information on the Yankee companies. Nonutility Generators: CL&P has entered into various arrangements for the purchase of capacity and energy from nonutility generators. These arrangements have terms from 10 to 30 years, currently expiring in the years 2001 through 2027, and requires the company to purchase energy at specified prices or formula rates. For the 12 months ended December 31, 1996, approximately 13 percent of system electricity requirements was met by nonutility generators. CL&P's total cost of purchases under these arrangements amounted to $279.5 million in 1996, $282.2 million in 1995, and $277.4 million in 1994. These costs are eventually recovered through the company's rates. 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 is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M and capital costs of these facilities. The estimated annual costs of CL&P's significant long-term contractual arrangements are as follows:
- -------------------------------------------------------------------- 1997 1998 1999 2000 2001 - -------------------------------------------------------------------- (Millions of Dollars) MYAPC and VYNPC......... $ 39.0 $ 33.1 $ 39.1 $ 38.9 $ 36.4 Nonutility generators............ 274.0 281.0 291.0 291.0 294.0 Hydro-Quebec............ 19.4 18.8 18.2 17.9 17.3
G. The Rocky River Realty Company - Obligations RRR provides real estate support services which includes the leasing of property and facilities used by system companies. RRR is the obligor under financing arrangements for certain system facilities. Under those financing arrangements, the holders of notes for $38.4 million would be entitled to request that RRR repurchase the notes if any major subsidiary of NU (as defined by the notes) has debt ratings below investment grade as of any year-end during the term of the financing. The notes are secured by real estate leases between RRR as lessor and F-41 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) NUSCO as lessee. The leases provide for the acceleration of rent equal to RRR's note obligations if RRR is unable to repay the obligation. The operating companies, primarily CL&P, WMECO and PSNH may be billed by NUSCO for their proportionate share of the accelerated lease obligations if the rateholders request repurchase of the notes. NU has guaranteed the notes. Based on the terms of the notes, PSNH and NAEC were defined as major subsidiaries of NU, effective as of the end of 1996, and both PSNH's and NAEC's debt ratings were below investment grade. In April 1997, the holders of approximately $38 million of the RRR notes elected to have RRR repurchase the notes at par. On July 1, 1997, RRR received commitments from alternative purchasers to purchase approximately $12 million of the notes that RRR had been required to repurchase. On July 30, 1997, approximately $6 million of the $12 million was purchased by an alternative purchaser. The remaining $6 million of notes are expected to be purchased by another purchaser by September 2, 1997. RRR repurchased the remaining $26 million of the notes on July 14, 1997. Management does not expect the resolution will have a material impact on CL&P's financial condition. 12. FUEL PRICE MANAGEMENT The company utilizes various financial instruments to manage well-defined fuel price risks. The company does not use these instruments for trading purposes. CL&P uses fuel-price management instruments with financial institutions to hedge against some of the fuel-price risk created by long-term negotiated energy contracts. These agreements minimize exposure associated with rising fuel prices and effectively fix a portion of CL&P's cost of fuel for these negotiated energy contracts. Under the agreements, CL&P exchanges monthly payments based on the differential between a fixed and variable price for the associated fuel. As of December 31, 1996, CL&P had outstanding agreements with a total notional value of approximately $228.8 million, and a positive mark-to-market position of approximately $1.1 million. As of June 30, 1997, CL&P had outstanding fuel price management agreements with a total notional value of approximately $318.4 million with a negative mark-to-market position of approximately $7.6 million. Under the terms of CL&P's fuel price management agreements, CL&P can be required to post cash collateral with its counterparties approximately equivalent to the amount of a negative mark-to-market position. In general, the amount of collateral is to be F-42 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information subsequent to December 31, 1996 is Unaudited) returned to CL&P when the mark-to-market position becomes positive, when CL&P meets specified credit ratings, or when an agreement ends and all open positions are properly settled. These agreements have been made with various financial institutions, each of which is rated "A" or better by Standard & Poor's rating group. CL&P is exposed to credit risk on fuel-price management instruments if the counterparties fail to perform their obligations. However, management anticipates that the counterparties will be able to fully satisfy their obligations under the agreements. 13. MINORITY INTEREST IN CONSOLIDATED SUBSIDIARY In January 1995, CL&P Capital LP (CL&P LP is a subsidiary of CL&P) 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 minority interests. 14. 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 nuclear decommissioning trusts: The carrying amounts approximate fair value. SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities," requires investments in debt and equity securities to be presented at fair value. As a result of this requirement, the investments held in the company's nuclear decommissioning trusts were adjusted to market by approximately $22.3 million as of December 31, 1996 and by approximately $14.4 million as of December 31, 1995, with corresponding offsets to the accumulated provision for depreciation. The amounts adjusted in 1996 and 1995, represent cumulative gross unrealized holding gains. The cumulative gross unrealized holding losses were immaterial for both 1996 and 1995. Preferred stock and long-term debt: The fair value of CL&P'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. F-43 The Connecticut Light and Power Company and Subsidiaries - ------------------------------------------------------------------------------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ------------------------------------------------------------------------------- (Information Subsequent to December 31, 1996 is Unaudited) The carrying amounts of CL&P's financial instruments and the estimated fair values are as follows:
------------------------------------------------------ Carrying Fair At December 31, 1996 Amount Value ------------------------------------------------------ (Thousands of Dollars) Preferred stock not subject to mandatory redemption.... $ 116,200 $ 111,845 Preferred stock subject to mandatory redemption....... 155,000 120,900 Long-term debt - First Mortgage Bonds....... 1,452,288 1,410,665 Other long-term debt....... 592,783 592,783 MIPS......................... 100,000 108,520 ------------------------------------------------------
------------------------------------------------------- Carrying Fair At December 31, 1995 Amount Value ------------------------------------------------------- (Thousands of Dollars) Preferred stock not subject to mandatory redemption.... $ 116,200 $ 82,448 Preferred stock subject to mandatory redemption....... 155,000 157,575 Long-term debt - First Mortgage Bonds....... 1,297,245 1,329,549 Other long-term debt....... 532,164 532,164 MIPS......................... 100,000 108,520 --------------------------------------------------------
The fair values shown above have been reported to meet disclosure requirements and do not purport to represent the amounts at which those obligations would be settled. F-44
- -------------------------------------------------------------------------------------------------------- STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) - -------------------------------------------------------------------------------------------------------- Quarter Ended(a) -------------------------------------------------- 1996 March 31 June 30 September 30 December 31 - -------------------------------------------------------------------------------------------------------- Operating Revenues.................................. $659,355 $542,999 $599,505 $595,601 ======== ======== ======== ======== Operating Income (Loss)............................. $ 59,977 $ 15,197 $ 593 $(45,994) ======== ======== ======== ======== Net Income (Loss)................................... $ 32,851 $(10,700) $(26,938) $(75,450) ======== ======== ======== ======== 1995 - -------------------------------------------------------------------------------------------------------- Operating Revenues.................................. $601,194 $525,147 $638,392 $622,336 ======== ======== ======== ======== Operating Income.................................... $ 96,191 $ 65,867 $ 88,012 $ 73,956 ======== ======== ======== ======== Net Income.......................................... $ 65,877 $ 38,089 $ 60,462 $ 40,788 ======== ======== ======== ========
(a) Reclassifications of prior data have been made to conform with the current presentation. F-45 The Connecticut Light and Power Company and Subsidiaries
- ---------------------------------------------------------------------------------------------------- STATISTICS - ---------------------------------------------------------------------------------------------------- Gross Electric Average Utility Plant Annual December 31, Use Per Electric (Thousands of kWh Sales Residential Customers Employees Dollars) (Millions) Customer (kWh) (Average) (December 31) - ------------------------------------------------------------------------------------------------------ 1996 $6,512,659 26,043 8,639 1,099,340 2,194 1995 6,389,190 26,366 8,506(a) 1,094,527 2,270 1994 6,327,967 26,975 8,775 1,086,400 2,587 1993 6,214,401 26,107 8,519 1,078,925 2,676 1992 6,100,682 25,809 8,501 1,075,425 3,028
(a) Effective January 1, 1996, the amounts shown reflect billed and unbilled sales. 1995 has been restated to reflect this change. F-46 ================================================================================ No dealer, salesperson, or any other person has been authorized to give any information or to make any representations other than those contained in this Prospectus, and, if given or made, such information and representations must not be relied upon as having been authorized by the Company. Neither the delivery of this Prospectus nor any sale made hereunder shall, under any circumstances, create any implication that there has been no change in the affairs of the Company since the date hereof. This Prospectus does not constitute an offer to sell or a solicitation by anyone in any jurisdiction in which such offer or solicitation is not authorized, or in which the person making such offer or solicitation is not qualified to do so or to any person whom it is unlawful to make such offer or solicitation. ________________ TABLE OF CONTENTS Available Information 4 Forward-looking Statements 4 Prospectus Summary 6 Risk Factors 13 The Company 18 The Original Offering 19 The Exchange Offer 19 Selected Financial Data 29 Management's Discussion and Analysis of Financial Condition and Results of Operations 30 Business 44 Employees 83 Properties 83 Legal Proceedings 85 Management And Compensation 90 Description of the New Bonds 99 Book-entry; Delivery and Form 105 Market For New Bonds 108 Certain Federal Income Tax Considerations 108 Plan of Distribution 110 Legal Matters and Experts 110 Glossary of Terms 111 Index to Consolidated Financial Statements F1
================================================================================ ================================================================================ Offer For All Outstanding First and Refunding Mortgage Bonds 1997 Series B Due June 1, 2002 In Exchange For First and Refunding Mortgage 7 3/4% Bonds 1997 Series C Due June 1, 2002 Each Issued By THE CONNECTICUT LIGHT AND POWER COMPANY ____________ PROSPECTUS ____________ September 2, 1997 ================================================================================ Part II Information Not Required In Prospectus Item 16. Exhibits and Financial Statement Schedules. (a) The following exhibits are filed herewith. Exhibit No. Description - ----------- ----------- 10.50 Description of Certain Management Compensation Arrangements. II-1 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, as amended, this amendment to the registration statement has been signed by the following persons in the capacities and on the dates indicated. Signature Title ) ) Hugh C. MacKenzie ) Hugh C. MacKenzie ) Principal Executive Officer President and Director ) ) John H. Forsgren ) John H. Forsgren ) Principal Financial Officer Executive Vice President, ) Chief Financial Officer ) and Director ) ) John J. Roman ) John J. Roman ) Principal Accounting Vice President and ) By Officer Controller ) /s/ Jeffrey C. Miller ) Jeffrey C. Miller Bernard M. Fox ) Attorney-in-Fact Bernard M. Fox Chairman and Director ) August 28, 1997 ) Robert G. Abair ) Robert G. Abair Director ) ) William T. Frain, Jr. ) William T. Frain, Jr. Director ) ) Cheryl W. Grise ) Cheryl W. Grise Director ) ) John B. Keane ) John B. Keane Director ) ) - ----------------- ) Bruce D. Kenyon Director ) ) II-2 EXHIBIT INDEX Exhibit No. Description - ----------- ----------- 10.50 Description of Certain Management Compensation Arrangements. 23 Consent of Independent Public Accountants EX-10.50 2 DESC. OF CERTAIN MGMT. COMPENSATION ARRANGEMENTS Exhibit 10.50 Description of Certain Management Compensation Arrangements The Board of Trustees of Northeast Utilities (NU) appointed Michael G. Morris as Chairman, President and Chief Executive Officer of NU effective August 19, 1997. Mr. Morris has been elected to comparable positions at most of the subsidiaries of NU, and to Chairman of the Board of Directors of The Connecticut Power and Light Company, also effective August 19, 1997. NU intends to enter into a five year employment agreement with Mr. Morris, the principal terms of which will provide for a starting salary of $750,000 per annum, a lump sum payment of $1,350,000, and non-qualified options to purchase 500,000 shares of NU stock at $9.625 per share, with exercise rights vesting in stages through August 20, 2001, subject to certain exceptions. Mr. Morris will also be eligible to participate in the short term and long term incentive compensation programs established by the NU system for senior level executive officers generally in 1998 and 1999, respectively. EX-23 3 CONSENT OF INDEPENDENT PUBLIC ACCOUNTS Exhibit 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS ----------------------------------------- As independent public accountants, we hereby consent to the use of our reports (and to all references to our Firm) included (or incorporated by reference) in this Registration Statement. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut August 26, 1997 -----END PRIVACY-ENHANCED MESSAGE-----