-----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, DkEp++frg9pDJDOvACzwGajJlz9pzM7GmVzMxuasCjdPtVJFJKrL+svCGhnMEVrK A13PVqP9cHfCRdAv25sJzw== 0000018808-97-000011.txt : 19970508 0000018808-97-000011.hdr.sgml : 19970508 ACCESSION NUMBER: 0000018808-97-000011 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970328 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CENTRAL VERMONT PUBLIC SERVICE CORP CENTRAL INDEX KEY: 0000018808 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 030111290 STATE OF INCORPORATION: VT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-08222 FILM NUMBER: 97566597 BUSINESS ADDRESS: STREET 1: 77 GROVE ST CITY: RUTLAND STATE: VT ZIP: 05701 BUSINESS PHONE: 8027732711 10-K405 1 FORM 10-K FOR PERIOD ENDING 12/31/96 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 _________ FORM 10-K (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1996 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from to Commission file number 1-8222 Central Vermont Public Service Corporation (Exact name of registrant as specified in its charter) Vermont 03-0111290 (State or other jurisdiction of (IRS Employer incorporation or organization) Identification No.) 77 Grove Street, Rutland, Vermont 05701 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (802) 773-2711 _____________________________________________________________________________ Securities registered pursuant to Section 12(b) of the Act: Name of each exchange on which Title of each class registered Common Stock $6 Par Value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes..X... No...... Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements or any amendment to this Form 10-K. [X] Cover page State the aggregate market value of the voting stock held by non- affiliates of the registrant: $141,116,913 based upon the closing price as of January 31, 1997 of Common Stock, $6 Par Value, on the New York Stock Exchange as reported in the Eastern Edition of the Wall Street Journal. Indicate the number of shares outstanding of each of the registrant's classes of Common Stock: As of January 31, 1997, there were outstanding 11,519,748 shares of Common Stock, $6 Par Value. DOCUMENTS INCORPORATED BY REFERENCE Specifically identified information on pages 5 through 19, inclusive of the registrant's 1997 Proxy Statement for the Annual Meeting of Shareholders to be held May 6, 1997 is incorporated as Part III hereof. Cover page continued Form 10-K - 1996 TABLE OF CONTENTS Page ---- PART I Item 1. Business................................................ 2 Item 2. Properties.............................................. 18 Item 3. Legal Proceedings....................................... 18 Item 4. Submission of Matters to a Vote of Security Holders..... 19 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.................................... 20 Item 6. Selected Financial Data................................. 21 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................... 22 Item 8. Financial Statements and Supplementary Data............. 36 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................... 63 PART III Item 10. Directors and Executive Officers of the Registrant...... 63 Item 11. Executive Compensation.................................. 65 Item 12. Security Ownership of Certain Beneficial Owners and Management............................................. 65 Item 13. Certain Relationships and Related Transactions.......... 65 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K............................................ 65 Signatures........................................................ 85 PART I Item 1. Business. Overview. Central Vermont Public Service Corporation (the "Company"), incorporated under the laws of Vermont on August 20, 1929, is engaged in the purchase, production, transmission, distribution and sale of electricity. The Company has various wholly and partially owned subsidiaries. These subsidiaries are described below. The Company is the largest electric utility in Vermont and serves 138,721 customers in nearly three-quarters of the towns, villages and cities in Vermont. This represents about 50% of the Vermont population. In addition, the Company supplies electricity to one municipal, one rural cooperative, and one private utility. The Company's sales are derived from a diversified customer mix. The Company's sales to residential, commercial and industrial customers accounted for 60% of total MWH sales for the year 1996. Sales to the five largest retail customers receiving electric service from the Company during the same period constituted about 5% of the Company's total electric revenues for the year. The Company's requirements resale sales accounted for approximately 5%, entitlement sales accounted for 14% and other resale sales which include contract sales, opportunity sales and sales to NEPOOL accounted for approximately 21% of total MWH sales for the year 1996. Connecticut Valley Electric Company Inc. (Connecticut Valley), a wholly owned subsidiary of the Company, incorporated under the laws of New Hampshire on December 9, 1948, distributes and sells electricity in parts of New Hampshire bordering the Connecticut River. It serves 10,341 customers in 13 communities in New Hampshire. About 2% of the New Hampshire population resides in its service area. Connecticut Valley's sales are also derived from a diversified customer mix. Connecticut Valley's sales to residential, commercial and industrial customers accounted for 99.5% of total MWH sales for the year 1996. Sales to its five largest retail customers during the same period equaled about 17% of Connecticut Valley's total electric revenues for the year. The Company also owns 56.8% of the common stock and 46.6% of the preferred stock of Vermont Electric Power Company, Inc. (VELCO). VELCO owns the high voltage transmission system in Vermont. VELCO created a wholly owned subsidiary, Vermont Electric Transmission Company, Inc. (VETCO), to finance, construct and operate the Vermont portion of the 450 KV DC transmission line connecting Quebec with Vermont and New England. In addition, the Company owns 31.3% of the common stock of Vermont Yankee Nuclear Power Corporation (Vermont Yankee), a nuclear generating company. The Company also owns 2% of the outstanding common stock of Maine Yankee Atomic Power Company, 2% of the outstanding common stock of Connecticut Yankee Atomic Power Company and 3.5% of the outstanding common stock of Yankee Atomic Electric Company. The Company also owns a real estate company, C.V. Realty, Inc. and two wholly owned subsidiaries were created for the purpose of financing and constructing two hydroelectric facilities in Vermont: Central Vermont Public Service Corporation - Bradford Hydroelectric, Inc. (Bradford), which became operational December 20, 1982, and Central Vermont Public Service Corporation - - - East Barnet Hydroelectric, Inc. (East Barnet), which became operational September 1, 1984. East Barnet has been leased and operated by the Company since its in-service date. Bradford was dissolved effective January 16, 1996. In addition, the Company has the following wholly owned non-utility subsidiaries: Catamount Energy Corporation whose primary purpose is to invest in non-regulated, energy-supply projects, SmartEnergy Services, Inc. whose purpose is to engage in the sale of or rental of electric water heaters, energy efficient products and other related goods and services, and Catamount Investment Corporation whose purpose is to invest in unregulated business opportunities. Catamount Energy Corporation currently has nine wholly owned subsidiaries: (See "DIVERSIFICATION"); Catamount Rumford Corporation, Equinox Vermont Corporation, Appomattox Vermont Corporation, Catamount Williams Lake L.P., Catamount Rupert Corporation, Catamount Glenns Ferry Corporation, Catamount Thetford Corporation, Gauley River Management Corporation and Summersville Hydro Corporation. For additional information of the Company's diversification activities, see PART II, Item 8 herein. REGULATION AND COMPETITION State Commissions. The Company is subject to the regulatory authority of the Vermont Public Service Board (PSB) with respect to rates, and the Company and VELCO are subject to PSB jurisdiction respecting securities issues, construction of major generation and transmission facilities and various other matters. The Company is subject to the regulatory authority of the New Hampshire Public Utilities Commission as to matters pertaining to construction and transfers of utility property in New Hampshire. Additionally, the Public Utilities Commission of Maine and the Connecticut Department of Public Utility Control exercise limited jurisdiction over the Company based on its joint-ownership interest as a tenant-in-common of Wyman #4, a 619 MW generating plant and Millstone #3, an 1149 MW nuclear generating facility, respectively. Connecticut Valley is subject to the regulatory authority of the New Hampshire Public Utilities Commission (NHPUC) with respect to rates, securities issues and various other matters. Federal Power Act. Certain phases of the businesses of the Company and VELCO, including certain rates, are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) as follows: the Company as a licensee of hydroelectric developments under PART I, and the Company and VELCO as interstate public utilities under Parts II and III of the Federal Power Act, as amended and supplemented by the National Energy Act. The Company has licenses expiring at various times under PART I of the Federal Power Act for twelve of its hydroelectric plants. The Company has obtained an exemption from licensing for the Bradford and East Barnet projects. Public Utility Holding Company Act of 1935. Although the Company, by reason of its ownership of a utility subsidiary, is a holding company, as defined in the Public Utility Holding Company Act of 1935, it is presently exempt, pursuant to Rule 2, promulgated by the Commission under said Act, from all the provisions of said Act except Section 9(a)(2) thereof relating to the acquisition of securities of public utility affiliates. Environmental Matters. In recent years, public concern for the physical environment has resulted in increased governmental regulation of environmental matters. The Company is subject to these regulations in the licensing and operation of the generation, transmission, and distribution facilities in which it has interest, as well as the licensing and operation of the facilities in which it is a co-licensee. These environmental regulations are administered by local, state and Federal regulatory authorities and concern the impact of the Company's generation, transmission, distribution, transportation and waste handling facilities on air, water, land and aesthetic qualities. The Company cannot presently forecast the costs or other effects which environmental regulation may ultimately have upon its existing and proposed facilities and operations. The Company believes that any such costs related to its utility operations would be recoverable through the rate-making process. For additional information relating to Electric Industry Restructuring see Item 7 herein and refer to Item 8 herein for disclosures relating to environmental contingencies, hazardous substance releases and the control measures related thereto. Nuclear Matters. The nuclear generating facilities of Vermont Yankee and the other nuclear facilities in which the Company has an interest are subject to extensive regulations by the Nuclear Regulatory Commission (NRC). The NRC is empowered to regulate the siting, construction and operation of nuclear reactors with respect to public health, safety, environmental and antitrust matters. Under its continuing jurisdiction, the NRC may, after appropriate proceedings, require modification of units for which operating licenses have already been issued, or impose new conditions on such licenses, and may require that the operation of a unit cease or that the level of operation of a unit be temporarily or permanently reduced. Refer to Item 8 herein for disclosures relating to the shut down of the Yankee Atomic Nuclear Power plant. Competition. Competition now takes several forms. At the wholesale level, other electric power providers compete as suppliers to resale customers. Another competitive threat is the potential for customers to form municipally owned utilities in the Company's service territory. At the retail level, customers have long had energy options such as propane, natural gas or oil for heating, cooling and water heating, and self-generation for larger customers. Changes anticipated as a result of the National Energy Policy Act of 1992 and potential future change in state regulatory policy may result in retail customers being able to purchase electric power generated by competing suppliers for delivery over the Company's transmission and distribution facilities. Pursuant to Vermont statutes (30 V.S.A. Section 249), the PSB has established as the service area for the Company the area it now serves. Under 30 V.S.A. Section 251(b) no other company is legally entitled to serve any retail customers in the Company's established service area except as follows: An amendment to 30 V.S.A. Section 212(a) enacted May 28, 1987 authorizes the Vermont Department of Public Service (Department) to purchase and distribute power at retail to all customers of electricity in Vermont, subject to certain preconditions specified in new sections 212(b) and 212(c). Section 212(b) provides that a review board consisting of the Governor and certain other designated legislative officers review and approve any retail proposal by the Department if they are satisfied that the benefits outweigh any potential risk to the State. However, the Department may proceed to file the retail proposal with the PSB either upon approval by the review board or the failure of the board to act within sixty (60) days of the submission. Section 212 provides that the Department shall not enter into any retail sales arrangement before the PSB determines and approves certain findings. Those findings are (1) the need for the sale, (2) the rates are just and reasonable, (3) the sale will result in economic benefit, (4) the sale will not adversely affect system stability and reliability and (5) the sale will be in the best interest of ratepayers. Section 212(d) provides that upon PSB approval of the Department retail sales proposal, Vermont utilities shall make arrangements for distributing such electricity on terms and conditions that are negotiated. Failing such negotiation, the PSB is directed to determine such terms as will compensate the utility for all costs reasonably and necessarily incurred to provide such arrangements. In addition, Chapter 79 of Title 30 authorizes municipalities to acquire the electric distribution facilities located within their boundaries. The exercise of such authority is conditioned upon an affirmative three-fifths vote of the legal voters in an election and upon the payment of just compensation including severance damages. Just compensation is determined either by negotiation between the municipality and the utility or, in the event the parties fail to reach an agreement, by the Public Service Board after a hearing. If either party is dissatisfied, the statute allows them to appeal the Board's determination to the Vermont Supreme Court. Once the price is determined, whether by agreement of the parties or by the PSB, a second affirmative three-fifths vote of the legal voters is required. There has been only one instance where Chapter 79 of Title 30 has been invoked; the Town of Springfield acted to acquire the Company's distribution facilities in that community pursuant to a vote in 1977. This action was subsequently discontinued by agreement between Springfield and the Company in 1985. In addition, in late 1994 the Select Board of the Town of Bennington considered whether to publicly warn a vote to acquire the Company's facilities located in Bennington pursuant to Chapter 79 of Title 30. By vote of the Selectors taken on January 9, 1995, the Town decided not to pursue the vote at this time. No other municipality served by the Company, so far as is known to the Company, has taken any formal steps in an attempt to establish a municipal electric distribution system. Competition in the energy services market exists between electricity and fossil fuels. In the residential and small commercial sectors this competition is primarily for electric space and water heating from propane and oil dealers. Competitive issues are price, service, convenience, cleanliness and safety. In the large commercial and industrial sectors, cogeneration and self-generation are the major competitive threats to electric sales. Competitive risks in these market segments are primarily related to seasonal, one-shift operations that can tolerate periodic power outages, and for industrial customers with steady heat loads where the generator's waste heat can be used in their manufacturing process. Competitive advantages for electricity in those segments are the cost of back up power sources, space requirements, noise problems, and maintenance requirements. In Docket DE 94-163, Order No. 21,683 (reh'g denied, Order No. 21,776), the New Hampshire Public Utilities Commission (NHPUC) ruled that Public Service Company of New Hampshire's (PSNH) rights to its franchise territory are not exclusive as a matter of law. Connecticut Valley was an intervenor in that docket. PSNH appealed the NHPUC's decision to the State of New Hampshire Supreme Court, and Connecticut Valley has filed a brief with the Court in favor of PSNH's position. This matter is still pending. In Docket DR 95-250, the NHPUC implemented a Retail Competition Pilot Program (Pilot), to determine the implications of retail competition in the electric utility industry. The Pilot is for a two-year period beginning in May 1996 and is open to all electric utilities and to 3% of all classes of customers in New Hampshire. For a discussion relating to Electric Industry Restructuring in Vermont and New Hampshire see PART II, Items 7 and 8 herein. For a discussion relating to the Company's wholesale electric business see Wholesale Rates below. RATE DEVELOPMENTS Vermont Retail Rates. On October 17, 1995, the Company filed for a rate increase of $31.0 million or 14.6%. For additional information regarding this rate increase request see PART II, Item 8 "Retail Rates" herein. In May 1995 the Company filed a comprehensive retail rate redesign. On March 17, 1997, the PSB issued an order approving the Company's rate redesign effective April 1, 1997. The redesign will narrow the seasonal rate differential by reducing the higher winter charges and increasing the lower summer charges. The rate redesign allocates the Company's total revenue requirement to the different customer classes and then establishes the specific rate structure within each class to fairly recover the cost allocated to that class. The Company recognizes adequate and timely rate relief is necessary, particularly since Vermont regulatory rules do not allow for changes in purchased power and fuel costs to be passed on to consumers through automatic rate adjustment clauses. The Company's practice of reviewing costs periodically will continue and rate increases will be requested when warranted. New Hampshire Retail Rates. Connecticut Valley's retail rate tariffs, approved by the New Hampshire Public Utilities Commission (NHPUC), contain a fuel adjustment clause (FAC) and a purchased power cost adjustment clause (PPCA). Under these clauses, Connecticut Valley recovers its estimated annual costs for purchased energy and capacity which are reconciled when actual data is available. On the basis of estimates of costs for 1996 and reconciliations from 1995, the combined PPCA and FAC resulted in an increase in revenues of approximately $1.2 million for 1996. The NHPUC order allowing the increase in 1996 revenues also ordered Connecticut Valley to file testimony and supporting material concerning the Hydro-Quebec/Vermont Joint Owners contract. The order also stated that the NHPUC would file a letter with the FERC requesting that the FERC issue a decision on the Wheelabrator complaint (see below) if one is pending or in the alternative inform the NHPUC as to when to expect a decision. On the basis of estimates of costs for 1997 and reconciliations from 1996, the combined PPCA and FAC will result in an increase in revenues of approximately $1.6 million for 1997. The order also required Connecticut Valley to file a letter showing whether a redesign of the RS-2 wholesale rate under which Connecticut Valley purchases power from Central Vermont would still be beneficial to ratepayers. See Wholesale Rates below for additional discussion. Connecticut Valley has filed a letter showing that the redesign is still beneficial to ratepayers, and added that filing or not filing the redesign would not relieve Connecticut Valley of responsibility to pay for Central Vermont stranded costs in the event of termination of the present RS-2 wholesale rate. The letter further stated that neither the Federal Energy Regulatory Commission (FERC) nor the NHPUC had the jurisdiction to order Central Vermont to open its transmission system to New Hampshire retail open access. See PART II, Items 7 and 8 herein for additional information regarding New Hampshire Electric Industry Restructuring. Connecticut Valley's retail rate tariffs, approved by the NHPUC, also provide for a Conservation and Load Management Percentage Adjustment (C&LMPA) for residential and commercial/industrial customers in order to collect forecast C&LM costs. The forecast costs are updated effective January 1 of each year and are reconciled when actual data are available. In addition, Connecticut Valley's earnings reflect the recovery of lost revenues related to fixed costs which Connecticut Valley fails to otherwise recover as a result of C&LM activities. However, the Company is not made whole because a portion of the fixed costs of the wholesale transaction between the Company and Connecticut Valley is not recovered when C&LM activities occur in Connecticut Valley. The C&LMPA further provides for the future recovery of shareholder incentives related to past C&LM activities. In November 1995 Connecticut Valley filed its annual update of the 1996 C&LMPA rates. The Company requested approval of a decrease in program spending and hence a decrease in revenues of $383,000 or 2.1%. Settlement negotiations resulted in a decrease in revenues of $519,000 or 2.8% effective March 4, 1996 which the NHPUC approved. In November 1996 Connecticut Valley filed its annual update of the 1997 C&LMPA rates. The Company requested approval of the same level of program spending as in 1996. Due to over/undercollections from the 1996 C&LMPA the filed increase is $163,000 or .8%. By agreement, the schedule will result in a rate change no earlier than April 1, 1997. Connecticut Valley also purchases power from several small power producers who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 1996, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 40,147 MWH, of which 37,203 MWH were purchased from a New Hampshire/Vermont solid waste plant owned by Wheelabrator Claremont Company, L.P., (Wheelabrator). Connecticut Valley has filed a complaint with FERC stating its concern that Wheelabrator has not been a qualifying facility since the plant began operation. Potential outcomes of this complaint could result in a refund, with interest, of past purchased power costs as well as lower future costs. Any refunds and lower future costs are likely to be reflected in the FAC. Pursuant to a Company request, the NHPUC issued an accounting order allowing deferral of litigation costs related to this FERC complaint, with recovery to be determined when the outcome of the FERC complaint is known and petitioned for implementation. In June 1995, the Legislature enacted House Bill 168 which directed the NHPUC to establish a pilot program to "examine the implications of retail competition in the electric industry" (RSA 374:26-a). In response to this mandate, the NHPUC issued Order No. 22,033 on February 28, 1996 which established statewide guidelines for a Retail Competition Pilot Program (Pilot or Pilot Program). Under the Pilot Program, which began May 28, 1996, approximately 17,000 retail customers gain the opportunity to purchase electricity from competitive non-utility power suppliers for two years. Connecticut Valley, as well as the other New Hampshire utilities, was ordered to make available three percent of its retail customers for the Pilot. In Connecticut Valley's case, this meant approximately 350 retail customers could become Pilot participants. The New Hampshire utilities were ordered to unbundle their prices for the Pilot participants and state separately transmission, distribution, and production prices. The NHPUC then determined a market price of production that was subtracted from the utilities embedded production price. The utilities are able to collect the difference between the embedded production price and the market production price through a charge known as the "stranded cost charge." As part of a proposal put forth to the NHPUC by Connecticut Valley, Pilot participants who elect to buy power from a non-utility supplier receive a discount on their bill known as a Participation Incentive Credit. The credit is designed such that a participating Pilot customer receives approximately ten percent off their combined non-power and power bills. These credit dollars are not recovered from Connecticut Valley's general body of customers. House Bill 1392 (RSA Chapter 374-F) directed the NHPUC to undertake a generic proceeding (Docket DR 96-150) to develop a statewide electric utility restructuring plan and to issue a final order establishing such a plan no later than February 28, 1997. The law directed the NHPUC to restructure New Hampshire's electric utility industry in order to introduce competition into the state's retail markets. RSA 374-F also authorized the NHPUC to establish an interim stranded cost charge for each electric utility as part of the aforementioned final order. RSA 374-F also requires all electric utilities subject to the NHPUC's jurisdiction to submit compliance filings no later than June 30, 1997 which shall be the subject of public hearings. The NHPUC is required to implement retail choice for all customers of electric utilities under its jurisdiction by January 1, 1998, or at the earliest date which the NHPUC determines to be in the public interest, but no later than June 30, 1998 without prior legislative approval (RSA 374-F:4,I). See PART II, Items 7 and 8 herein for additional information regarding New Hampshire Electric Industry Restructuring. By letter dated July 23, 1996 Connecticut Valley filed with the NHPUC (1) for a permanent base rate increase of $1,592,000 or 8.8% effective September 22, 1996, (2) for a temporary base rate increase of $924,000 or 5.4% effective August 23, 1996, and (3) to reflect the permanent base rate increase in tariffs for Pilot customers. PART II, Items 7 and 8 herein contain additional information regarding the permanent base rate increase request. Wholesale Rates. The Company sells firm power to Connecticut Valley under a wholesale rate schedule based on forecast data for each calendar year which is reconciled to actual data annually. The rate schedule provides for an automatic update of annual rates, as well as a subsequent reconciliation to actual data. The Company filed and the FERC approved (1) a revenue decrease of $78,000 or .7% for 1996 power costs, (2) a reconciliation of 1995 revenues to actual costs which resulted in a refund of $553,794, including interest, and (3) a revenue increase of $918,000 or 8.8% for 1997 power costs. The NHPUC order dated February 28, 1997 regarding New Hampshire Electric Industry Restructuring ordered, among other things, Connecticut Valley to terminate the wholesale rate schedule with the Company. See PART II, Item 7 herein for additional information. As ordered by the NHPUC in Connecticut Valley's 1994 C&LMPA docket, the Company entered into negotiations with the NHPUC Staff to redesign the RS-2 wholesale rate under which Connecticut Valley purchases power from the Company. The redesign features marginal cost based energy and capacity charges for all energy and capacity purchases above or below a base level. Such negotiations concluded in February 1995. A summary report was filed with the NHPUC on February 13, 1995. The NHPUC issued an order approving the summary report in June 1995. Connecticut Valley's costs of wholesale power would be lower than they otherwise would be only if Connecticut Valley's growth rate exceeds that of the Company's Vermont retail operations. In light of the NHPUC order dated February 28, 1997 regarding New Hampshire Electric Industry Restructuring the Company may not file the redesign with the FERC. See PART II, Item 8 herein for additional information. One of the Company's requirements wholesale customers, New Hampshire Electric Cooperative, Inc. (NHEC), with an average monthly peak of 2.8 MW gave the Company notice of termination of service under FERC Electric Tariff, effective in March 1995. The Company negotiated a interim temporary power sale to NHEC commencing with the termination date and a long-term power sale effective May 1, 1995. On March 1, 1995, the Company filed a comprehensive, open access transmission tariff (Tariff) with the FERC. The Tariff is designed to provide firm and non-firm network transmission service, as well as firm point-to-point service over the transmission systems of the Company and Connecticut Valley. In addition, the Tariff would permit customers to make use of the Company's contract rights to the transmission facilities of the Vermont Electric Power Company, Inc. and New England Power Company. The Tariff would provide transmission service that is comparable to that provided to native load customers. Charges for such service would be based upon the Company's cost of service for transmission. The Company prepared and filed the Tariff in anticipation of developing business opportunities in the area of electric transmission service. In addition, recent FERC orders led the Company to believe that all electric utilities owning transmission facilities would be required to prepare and file such a Tariff in the near future. FERC issued a Notice Of Proposed Rulemaking (NOPR) dated March 29, 1995, promoting wholesale competition in the electric utility industry. The Company's Tariff complies with many requirements proposed by the FERC in its NOPR. Nine parties intervened in the Company's Tariff filing. On April 28, 1995, the FERC issued a deficiency letter asking for more information in a number of areas. The Company filed a timely response to the deficiency letter on June 14, 1995. Three parties filed protests in response to the Company filing, and one additional party filed a request for late intervention. The FERC accepted the Tariff for filing on August 14, 1995, suspended it and set it for hearing. The order allowed the Tariff to become effective August 15, 1995, subject to refund and subject to the outcome of the Open Access NOPR proceeding. The NHEC began taking transmission service under the Tariff as of its effective date. The Company entered into negotiations with FERC Staff and intervenors and reached a settlement in principle in January 1996 on all rate issues contained in the Tariff filing but one which was settled in August 1996. The settlement provided for a fixed rate effective from August 15, 1995 through July 8, 1996. On July 9, 1996 the Tariff was replaced by a pro forma transmission tariff (Transmission Tariff) filed by the Company pursuant to FERC Order No. 888. The Transmission Tariff embodied not only the open access principles set forth in the FERC pro forma transmission tariff, but also continued to embody the ratemaking and other Vermont and New England specific non-rate terms and conditions. There has been no action by the FERC since the filing date. POWER RESOURCES Overview. The Company's and Connecticut Valley's energy production, which includes generated and purchased power, required to serve their retail and firm wholesale customers was 2,464,766 MWH for the year ended December 31, 1996. The maximum one-hour integrated demand during that period was 409.9 MW, which occurred on December 31, 1996. The Company's and Connecticut Valley's total production in 1996, including production related to all resale customers, was 3,754,338 MWH. The following tabulation shows the sources of such energy and capacity available to the Company and Connecticut Valley for the year ended December 31, 1996 and at the time of the Company's own peak. For additional information related to purchased power costs, refer to PART II, Item 7 herein.
Year Ended December 31, 1996 -------------------------------------------------- Effective Generated and Capability Purchased at 12 Month Generated Time of the Average and Purchased Company's Peak ---------- ---------------- -------------- MW MWH % MW % WHOLLY-OWNED PLANTS: Hydro....................... 40.8 219,710 5.9 34.7 8.4 Diesel and Gas Turbine..... 28.7 207 - - - JOINTLY OWNED PLANTS: Millstone #3................ 19.7 42,873 1.2 - - Wyman #4.................... 10.9 5,613 0.1 - - McNeil...................... 10.5 27,400 0.7 10.1 2.5 EQUITY OWNERSHIP IN PLANTS: (Purchased) Vermont Yankee.............. 158.8 1,174,418 31.3 136.5 33.3 Maine Yankee................ 15.7 90,776 2.4 - - Connecticut Yankee.......... 10.5 55,404 1.5 - - MAJOR LONG-TERM PURCHASES: Hydro-Quebec................ 185.8 982,161 26.2 159.0 38.8 Merrimack #2... ............. 47.0 291,444 7.8 47.1 11.5 OTHER PURCHASES: System and other purchases.. 47.4 238,138 6.3 0.4 .1 Small power producers....... 32.9 219,584 5.8 25.1 6.1 Unit purchases.............. 22.6 56,216 1.5 - - Entitlement purchases....... 0.4 11,226 0.3 - - Pumped storage hydro........ 4.2 3,422 0.1 0.7 0.2 NEPEX......................... - 335,748 8.9 (3.7) (0.9) ----- --------- ----- ----- ----- TOTAL.................... 635.9 3,754,338 100.0 409.9 100.0 ===== ========= ===== ===== =====
Wholly Owned Plants. The Company owns and operates 20 hydroelectric generating facilities in Vermont which have an aggregate nameplate capability of 41.2 MW and two gas-fired and one diesel-peaking units with a combined nameplate capability of 28.9 MW. Jointly Owned Plants. The Company has a joint-ownership interest in the following generating and transmission plants:
Net Fuel MW Generation Load Net Plant Name Location Type Ownership Entitlement MWH Factor Investment - - ------------ ----------- ------- --------- ----------- ------ ------ ----------- Millstone #3 Waterford, Nuclear 1.73% 20 42,873 24% $55,945,467 Connecticut Wyman #4 Yarmouth, Oil 1.78% 11 5,613 6% $ 1,560,826 Maine Joseph C. McNeil Burlington, Various 20.00% 10.6 27,400 29% $ 8,499,788 Vermont Highgate Trans- Highgate Springs, 46.08% N/A N/A N/A $ 8,702,073 mission Facility Vermont
The Company receives its share of the output and capacity of Millstone Unit #3 (Unit #3), an 1149 MW nuclear generating facility (see discussion below); and Wyman #4 and Joseph C. McNeil, a 619 MW and a 53 MW respectively, generating plants and is responsible for its share of the operating expenses of each. The Highgate Convertor, a 200 MW facility is directly connected to the Hydro-Quebec System to the north of the Convertor and to the VELCO System for delivery of power to Vermont Utilities. This facility can deliver power either direction, but normally delivers power from Hydro-Quebec to Vermont. Equity Ownership in Plants. In 1966 the Company purchased 35% of the Vermont Yankee common stock and was entitled to receive a like percentage of the output of the unit. In late 1969 and early 1970, the Company sold at cost a combined total of 3.7% of its original equity investment and currently resells at cost 4.5% of its entitlement. The Company's current equity ownership and net entitlement percentages are 31.3 and 30.5, respectively. The Atomic Energy Commission, now the NRC, granted a full-term (40-year), full power operating license for the Vermont Yankee plant, which was to expire in December 2007. On December 17, 1990 the NRC issued an amendment of the operating license extending its term to March 2012. Vermont Yankee's net capability is 514 MW of which 156.7 MW (See Note 1) is the Company's net entitlement. Vermont Yankee's plant performance for the past five years is shown below: Availability Capacity Factor Factor (See Note 2) (See Note 3) ------------ ------------ 1992......................... 87.5 82.7 1993......................... 78.3 74.9 1994......................... 98.2 95.8 1995......................... 86.3 84.8 1996......................... 84.5 82.8 Vermont Yankee was down for scheduled refueling outages in 1995 and 1996. As described in the overview section above, the Company is a stockholder, together with other New England electric utilities, in the following three nuclear generating companies: Maine Yankee Atomic Power Company, Connecticut Yankee Atomic Power Company and Yankee Atomic Electric Company. Net Company's Company Capability Entitlement ------- ---------- -------------- Maine Yankee (See Note 4)..... 847 MW 2.0% - 16.9 MW Connecticut Yankee............ (See Note 5) (See Note 5) Yankee Atomic................. (See Note 5) (See Note 5) The Company is obligated to pay its entitlement percentage of the operating expenses of Vermont Yankee and the other Yankee companies, including depreciation and a return on invested capital, whether or not the plant is operating. The Company is obligated to contribute its entitlement percentage of the capital requirements of Vermont Yankee and Maine Yankee and has a similar, but more limited obligation to Connecticut Yankee. The Company's entitlement percentages are identical to the ownership percentages except that Vermont Yankee's entitlement percentage is 35%. For additional information regarding Equity Ownership in Plants, refer to PART II, Item 8 herein. Decommissioning Expense. Each of the Yankee companies and Unit #3 has developed its own estimate of the cost of decommissioning its nuclear generating unit. These estimates vary depending upon the method of decommissioning, economic assumptions, site and unit specific variables, and other factors. Each of the Yankee Companies includes charges for decommissioning costs in the cost of capacity, as approved by the FERC. Decommissioning costs for Unit #3 are included in depreciation expenses. _______________ Notes: (1) Currently, the Company resells at cost, through VELCO, 23.2 MW of its original entitlement to other Vermont utilities. (2) "Availability Factor" means the hours that the plant is capable of producing electricity divided by the total hours in the period. (3) "Capacity Factor" means the total net electrical generation divided by the product of the maximum design electrical rating capacity of 514 through April 30, 1995 and 522 effective May 1, 1995, multiplied by the total hours in the period. (4) Currently, the Company resells at cost 1.8 MW of its entitlement to certain municipal utilities in Massachusetts. (5) Connecticut Yankee and Yankee Atomic permanently ceased power operations of their Nuclear Power Plants. See Decommissioning Expense discussion below. The Company's entitlement percentage of decommissioning costs for Vermont Yankee, Connecticut Yankee, Maine Yankee, Yankee Atomic and Unit #3 is as follows (dollars in millions): CVPS's Total Share of Date of Estimated CVPS's Funded Study Obligation Obligation Obligation ------- ---------- ---------- ---------- Nuclear generating companies: Vermont Yankee 1993 $312.7 $109.4 $53.3 Maine Yankee 1993 $316.6 $6.3 $3.3 Connecticut Yankee 1996 $426.7 $8.5 $4.1 Yankee Atomic 1994 $370.0 $13.0 $4.6 Millstone Unit #3 1995 $426.7 $7.4 $1.7 Although the estimated costs of decommissioning are subject to change due to changing technologies and regulations, the Company expects that the nuclear generating companies' liability for decommissioning, including any future changes in the liability, will be recovered in their rates over their operating or license lives. See PART II, Item 8 for additional disclosure. The Company owns interests in two of the five nuclear plants operated by Northeast Utilities (NU): 1) a 2% equity interest in the Connecticut Yankee Atomic Power Company (Haddam Neck Plant), and 2) a 1.7303% joint-ownership interest in the Unit #3 of the Millstone Nuclear Power Station. On January 31, 1996, the Nuclear Regulatory Commission (NRC) placed the Millstone Nuclear Power Station on its "watch list." On March 30, 1996, NU decided to shut down Unit #3 following an engineering evaluation which determined that four safety-related valves would not be able to perform their design function during certain assumed events. In July 1996, NU reported that on July 2, 1996, Northeast Utilities Service Company (NUSCO) filed an extensive document with the NRC responding to a series of requests from the NRC seeking assurance that Unit #3 will be operated in accordance with the terms of its operating license and other NRC requirements and regulations and also dealing with a series of issues that NU has identified in the course of these reviews. The document also included an Operational Readiness Plan for Unit #3 which is currently under review by the NRC. On August 14, 1996, an independent review team was created by the NRC to review actions to be taken by NU prior to the restart of Unit #3. On October 18, 1996, the NRC informed NU that it will establish a Special Projects Office to oversee inspection and licensing activities at Millstone. The Special Projects Office will be responsible for 1) licensing and inspection activities at NU's nuclear units, 2) oversight of an 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 nuclear units' restart activities. On October 24, 1996, the NRC issued an order requiring NU to devise and implement a comprehensive plan for handling safety concerns raised by Millstone Nuclear Power Station employees for ensuring an environment free from retaliation and discrimination and to retain an independent third-party to monitor and review NU's performance in handling employee concerns. NU's management has indicated it cannot presently estimate the timing of the restart of Unit #3 or what additional costs, if any, will be incurred. The company remains actively involved with the other non-operating minority joint-owners of Unit #3. This group is engaged in various activities to monitor and evaluate NU/NUSCO's efforts relating to Unit #3. In addition, this group has retained counsel and experts to review and evaluate NU/NUSCO's operation and management and any prospective claims the group members may be able to assert against NU/NUSCO or related companies. For information regarding the premature shutdown of the Connecticut Yankee and Yankee Atomic nuclear power plants, Maine Yankee's extended shutdown and Vermont Yankee's Design Basis Documentation project, refer to PART II, Item 8 herein. In 1982 the State of Maine enacted legislation that requires the development of a decommissioning trust fund for the Maine Yankee nuclear plant. This statute also provides that, if the trust has insufficient funds to decommission the plant, the licensee, Maine Yankee, is responsible for the deficiency and, if the licensee is unable to provide the entire amount, the owners of the licensee are jointly and severally responsible for the remainder. The definition of owner under the statute includes the Company. It is expected that any payments required by the Company under these provisions would be recovered through rates. Nuclear Fuel. Vermont Yankee has several "requirements based" contracts for the four components (uranium, conversion, enrichment and fabrication) used to produce nuclear fuel. These contracts are executed only if the need or requirement for fuel arises. Under these contracts, any disruption of operating activity would allow Vermont Yankee to cancel or postpone deliveries until actually required. The contracts extend through various time periods and contain clauses to allow the option to extend the agreements. Negotiation of new contracts or renegotiation of existing contracts routinely occurs, often focusing on one of the four components at a time. The price of the 1996 reload was approximately $21 million and future reload costs will depend on market and contract prices. Under the Nuclear Waste Policy Act of 1982, the United States Department of Energy (DOE) is responsible for the selection and development of repositories for and the disposal of spent nuclear fuel and high-level radioactive waste. Vermont Yankee, as required by that Act, has signed a contract with the DOE to provide for the disposal of spent nuclear fuel and high-level radioactive waste from its nuclear generation station beginning no later than January 31, 1998; however, this delivery schedule is expected to be delayed significantly. It is not certain when the DOE will accept spent nuclear fuel and high-level radioactive waste. Extended delays or a default by the DOE would lead to consideration of costly alternatives involving serious siting and environmental issues. The DOE contract obligates Vermont Yankee to pay a one-time fee of approximately $39.3 million for disposal costs for all spent fuel discharged through April 6, 1983, and a fee payable quarterly equal to approximately one mill per kilowatt-hour of nuclear generated and sold electricity after April 6, 1983. Although such amount for the one-time fee has been collected in rates from the Sponsors, Vermont Yankee has elected to defer payment to the DOE as permitted by the DOE contract. The fee plus accrued interest must be paid no later than the first delivery of spent fuel to the DOE. Interest accrues on the unpaid obligation based on the thirteen-week Treasury Bill rate and is compounded quarterly. Through 1996, Vermont Yankee accumulated $78.2 million in an irrevocable trust to be used exclusively for defeasing this obligation ($93.7 million including accrued interest) at some future date, provided the DOE complies with the terms of the aforementioned contract. Vermont Yankee has primary responsibility for the interim storage of its spent nuclear fuel. The plant is currently able to operate with the ability to discharge the entire reactor core to the spent fuel storage pool through the 2001 refueling outage. Full core discharge capability through the 2004 refueling outage could be achieved with the installation of additional storage racks in the spent fuel pool. Vermont Yankee is currently investigating options for new and separate storage facilities in the event spent fuel storage requirements go beyond this period. The costs of these options have not yet been determined. The average energy and capacity costs to the Company of energy generated at the Vermont Yankee plant was 4.71, 5.34, 3.77, 4.68 and 4.78 cents per KWH for the years 1992 through 1996, respectively. The Company has been advised by the companies operating other nuclear generating stations in which the Company has an interest that they have contracted for certain segments of the nuclear fuel production cycle through various dates. Contracts for the remainder of the fuel cycle will be required but their availability, prices and terms cannot be predicted. Nuclear Liability and Insurance. The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. Beyond that a licensee maintains an indemnity agreement with the Nuclear Regulatory Commission, but subject to Congressional approval. The first $200 million of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection Program is a retrospective insurance plan providing additional coverage up to $8.7 billion per incident by assessing $79.3 million against each of the 110 reactor units that are currently subject to the Program in the United States, limited to a maximum assessment of $10 million per incident per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes. The company's interests in the nuclear power units are such that it could become liable for an aggregate of approximately $3.9 million of such maximum assessment per incident per year. Major long-term purchases. Canadian Purchases - Under various contracts, the Company purchases from Hydro-Quebec capacity and associated energy. Under the terms of these contracts, the Company is required to pay certain fixed capacity costs whether or not energy purchases above a minimum level described in the contracts are made. Such minimum energy purchases must be made whether or not other less expensive energy sources might be available. The company will receive varying amounts of capacity and energy from Hydro-Quebec under the Vermont Joint Owners (VJO) contract during the 1997 to 2016 period. A contract between the State of Vermont and Hydro-Quebec terminated on September 22, 1995. Related contracts were negotiated between the company and Hydro-Quebec which in effect alter the terms and conditions contained in the VJO contract, reducing the overall power requirements and cost of the original contract. The maximum net amount of capacity that the company will purchase during the term of the Hydro-Quebec agreements is 143 MW. The total commitment in the next five years to purchase power under these contracts is approximately $355 million, less approximately $80 million of power sellbacks, yielding a net cost of approximately $275 million. In February 1996, the company reached an agreement with Hydro-Quebec that will lower our 1997 cost of power by approximately $5.8 million. As part of this agreement, the company will deliver to NEPOOL under existing firm energy contracts or joint marketing activities 54 MW of Phase II transmission capacity for a five-year period beginning July 1, 1996 through June 30, 2001. In addition, the agreement provides for continuing negotiations with Hydro-Quebec to further reduce future power cost increases. In the early phase of the VJO contract, two sellback contracts were negotiated, the first delaying the purchase of about 24 MW of capacity and associated energy, the second reducing the net purchase of Hydro-Quebec power. In 1994, the company negotiated a third sellback arrangement whereby the company receives an effective discount on up to 70 MW of capacity starting in November 1995 for the 1996 contract year (declining to 30 MW in the 1999 contract year). In exchange for this sellback, Hydro-Quebec has the right to reduce capacity deliveries by up to 50 MW beginning as early as 2004 until 2015, including the use of a like amount of the company's Phase I/II facility rights and the ability to reduce the amounts of energy delivered during a five-year term beginning in 2000. Details of these purchases and sell-back contracts are described in the table that follows (dollars in thousands):
Schedule Schedule Schedule Schedule C-1 C-2 B C4-a -------- -------- -------- -------- Capacity in MW 31 21 93 24 Contract period '91-'12 '92-'12 '95-'15 '96-'16 Energy capacity factor 75.0% 75.0% 75.0% 75.0% Annual contract year energy in MWH 201,863 138,141 610,077 155,801 Actual 1996 energy charges $4,389 $2,305 $14,672 $571 Estimated 1997 energy charges $4,803 $3,287 $14,517 $3,707 Estimated future average % change from 1997 2.75% 2.75% 2.75% 2.75% Actual 1996 annual capacity charge $7,429 $5,043 $23,676 $992 Estimated 1997 capacity charge $7,248 $4,960 $23,515 $5,952 Estimated future average % change from 1997 0.0% 0.0% 0.0% 0.0% 1996 average cost in cents/KWH 6.6 7.9 6.4 6.9 Estimated 1997 average cost in cents/KWH 6.4 6.4 6.7 6.6 Estimated future average % change from 1997 1.1% 1.1% 1.0% 1.1% 1996 sellback in average annual MW 30 17 N/A N/A 1996 sellback revenue $10,914 $3,914 $15,406 N/A Expected sellback #1 revenue 25 MW 100% of costs Estimated 1997 annual $9,806 Estimated out-years average annual $10,641 Estimated average annual % change 1.1% ('98-'12) Expected sellback #3 revenue up to 70 MW Approx. 90% of capacity costs 1st contract year: 11/1/95 - 10/31/96 $16,195 70 MW Est. 2nd contract yr: 11/1/96 - 10/31/97 $11,462 50 MW Est. 3rd contract yr: 11/1/97 - 10/31/98 $9,170 40 MW Est. 4th contract yr: 11/1/98 - 10/31/99 $6,877 30 MW Expected sellback #4 revenue - estimated 1997 annual $5,800
Merrimack #2 - The Company, through Velco, purchases power from Merrimack #2, a 320 MW capacity coal-fired steam unit located in Bow, New Hampshire, and owned by NU under a thirty-year contract which expires April 30, 1998. The Merrimack #2 unit is subject to air emission limits for sulfur dioxide (SO2) and Nitrogen Oxides (NOx) mandated by the Clean Air Act Amendments of 1990 (CAAA). The CAAA establishes SO2 allowances to reduce SO2 emissions. NU expects to have sufficient SO2 allowances to meet CAAA SO2 requirements. If any gains are realized from the sale of excess allowances, the Company will receive its proportionate share from VELCO. Likewise, the Company will pay its share of any allowances purchased. NU complied with the Merrimack #2 NOx limits by installing Selective Catalytic Reduction (SCR) equipment in 1995 at a cost of approximately $19 million increasing operating costs by about $1.6 million annually. The SCR equipment is expected to have a negligible effect on unit fuel efficiency. The Company will share on a pro-rata basis the cost of the SCR equipment based on its share of the VELCO contract. The total cost to the Company of energy generated by the Merrimack #2 unit was 3.31 cents per KWH in 1996. Under the Clean Air Act Amendment of 1990, the plant is required to purchase allowances if its output of sulfur dioxide (SO2) exceeds about 21,400 tons of which the Company's share is about 3,200 tons. In 1996, Merrimack 2 emitted about 24,000 tons and the Company's share was about 3,500 tons, which required the purchase of 2,275 allowances for total plant. The Company's share was about 341 allowances which cost approximately $43,000. Other Purchases. Cogeneration/Small Power Qualifying Facilities - A number of small producers using hydroelectric, biomass, and refuse-burning generation are currently producing energy that the Company is purchasing. For the year ended December 31, 1996, the Company received 219,584 MWH from these sources for which it paid $22,116,441. New England Power Pool (NEPOOL) - The Company, through VELCO, is a participant in NEPOOL, which is open to all investor-owned, municipal and cooperative utilities in New England under an agreement in effect since 1971. The NEPOOL Agreement provides for joint planning and operation of generating and transmission facilities and also incorporates generating capacity reserve obligations and provisions regarding the use of major transmission lines and payment for such use. Because of its participation in NEPOOL, the Company's operating revenues and costs are affected to some extent by the operations of other participants in that agreement. The primary purposes of NEPOOL are to provide energy reliability for the region, centralized economic dispatch and coordination of generation planning and construction by the individual participants. The Company's peak demand for 1996 occurred on December 31 and equaled 409.9 MW. At the time of this peak, the Company had a reserve margin of 24%. NEPOOL's peak for the year occurred on August 6, 1996 and totaled 19,507 MW. NEPOOL had a 34% reserve margin at the time of its 1996 peak. Power Resources - Future. The Company has generally sufficient power under contract to supply its current franchise obligations for the near-term prior to any advent of Retail Wheeling. In addition, the Company will utilize cost effective demand side management programs where appropriate. The Company expects to actively manage this portfolio of supply and demand side resources over the near-term, as it has in the past, to minimize net power costs for its ratepayers and shareholders. It is unclear what the Company's load responsibilities will be upon the advent of Retail Wheeling. The certainty, timing and nature of these events will be largely determined by legislative and regulatory actions at the state and national levels. TRANSMISSION Vermont Electric Power Company, Inc. VELCO engages in the operation of a high-voltage transmission system which interconnects the electric utilities in the State including the areas served by the Company. VELCO is also engaged in the business of purchasing bulk power for resale, at cost, to the Company and the other electric utilities (cooperative, municipal and investor-owned) in Vermont (the "Vermont utilities") and transmitting such power for the Vermont utilities. Refer to Item 8 herein for a discussion of the 1985 Four Party Agreement between the Company, VELCO and two other major distribution companies in Vermont. VELCO provides transmission services for the State of Vermont, acting by and through the Department, and for all of the electric distribution utilities in the State of Vermont. VELCO is reimbursed for its costs (as defined in the agreements relating thereto) for the transmission of power for such entities. The Company, as the largest electric distribution utility in Vermont, is the major user of VELCO's transmission system. The Company owns 34,083 shares (56.8%) of the Class B common stock of VELCO, the balance being owned by other Vermont utilities. Each share of Class B common stock has one vote. The Company also owns 46,624 shares (46.6%) of the Class C preferred stock of VELCO, the balance being owned by other Vermont utilities. Shares of Class C preferred stock have no voting rights except the limited right to vote VELCO's shares of common stock in Vermont Electric Transmission Company, Inc. (VETCO) if certain dividend requirements are not met. NEPOOL Arrangements. VELCO participates for itself and as agent for the Company and twenty-one other Vermont utilities in NEPOOL. See "Business-New England Power Pool" for additional details. Capitalization. VELCO has authorized 92,000 shares of Class B common stock, $100 par value, of which 60,000 shares were outstanding on December 31, 1996 and 125,000 shares of Class C preferred stock, of which 100,000 shares were outstanding at December 31, 1996. On that date there were authorized and outstanding three issues of First Mortgage Bonds, aggregating $30,887,000, issued under an Indenture of Mortgage dated as of September 1, 1957, as amended, between VELCO and Bankers Trust Company, as Trustee (the "VELCO Indenture"). The issuance of bonds under the VELCO Indenture is unlimited in amount but is subject to certain restrictions. New transmission and associated facilities will be required by VELCO in 1997 to transmit power to Vermont utilities. The costs of such facilities are presently estimated at $2,400,000 including allowance for funds used during construction calculated at a rate of approximately 6.2%. For a description of VELCO's properties, see "VELCO" under Item 2. Management. In 1957 VELCO entered into an agreement (the "Three-Party Agreement") whereby the Company and Green Mountain agreed that, if VELCO transmits firm power owned by it (which it does not now do), they would have the right to purchase all such firm power not sold to others with their consent and the obligation to pay (in agreed proportions) amounts sufficient, together with VELCO's revenues from other sources, to pay all VELCO's operating expenses, debt service and taxes. In connection with the transfer to VELCO of entitlements of the output of the Vermont Yankee plant, the Company and Green Mountain entered into a Three-Party Transmission Agreement, dated November 21, 1969, as amended, whereby they have agreed to pay transmission charges thereon in an aggregate amount sufficient, with VELCO's other revenues, to pay all of VELCO's expenses including capital costs. VELCO's Bonds are secured by a first mortgage on the major part of VELCO's transmission properties and by the assignment to the Trustee of the Three-Party Agreement, the Three-Party Transmission Agreement and certain other contracts as specified in the VELCO Indenture. See Item 8 herein for information relating to the 1985 Four-Party Agreement. Vermont Electric Transmission Company, Inc. In connection with the importing of Canadian power, VELCO has created a wholly owned subsidiary, VETCO, to construct, finance, own and operate the Vermont portion of the transmission line which connects the Hydro-Quebec lines at the Canadian border to the lines of New England Electric Transmission Corporation, a subsidiary of New England Electric System, at the New Hampshire border on the Connecticut River. VETCO entered into a Capital Funds Agreement with VELCO pursuant to which VETCO may request up to $12,500,000 (of which $10,000,000 was contributed as of December 31, 1995) of capital contributions from VELCO and has entered into Transmission Line Support Agreements with 20 New England utilities, including VELCO as representative for 15 Vermont utilities, pursuant to which those utilities have agreed to pay the transmission line costs, whether or not the line is operational. VELCO, as such representative, has entered into a similar agreement with New England Electric Transmission Corporation with respect to the New Hampshire portion of the DC transmission line and the DC/AC converter station. VELCO has entered into a Vermont Participation Agreement and a Capital Funds Support Agreement with 15 Vermont distribution utilities, including the Company, pursuant to which those utilities assume their pro rata share (based upon 1980 sales) of the benefits and obligations of VELCO under the Support Agreements and the VETCO Capital Funds Agreement. VETCO has authorized 10 shares of common stock, $100 par value, all of which were outstanding on December 31, 1996 and owned by VELCO, with each share having one vote. During 1986 VETCO paid off its construction financing by issuing $37,000,000 of secured notes, maturing in 2006, and receiving a $9,999,000 equity contribution from VELCO. The notes are secured by a First Mortgage on the major part of VETCO's transmission properties and by the assignment of its rights under the Support Agreements. Phase I and Phase II. The Company participated with other electric utilities in the construction of the Phase I Hydro-Quebec transmission facilities in northeastern Vermont, which were completed at a total cost of approximately $140 million. Under a support agreement relating to the Company's participation in the facilities, the Company is obligated to pay its 4.42% share of Phase I Hydro-Quebec capital costs over a 20 year recovery period through and including 2006. The Company also participated in the construction of Phase II Hydro-Quebec transmission facilities which began operation in November 1990. This service increased the maximum capacity of the Hydro-Quebec 450 KV DC line from 690 MW to 2000 MW and extended Phase I line from Comerford, New Hampshire to Sandy Pond, Massachusetts. The Company uses this transmission path to deliver a portion of the Company's long-term Hydro-Quebec firm power contract. The project cost approximately $487 million. Under a similar support agreement, the Company is obligated to pay its 5.132% share of Phase II Hydro-Quebec capital costs over a 25-year recovery period through and including 2015. Under the support agreement, the Company is eligible for savings associated with certain energy transactions by NEPOOL, which will offset the Company's support cost obligations. Due to the Vermont Electric Generation and Transmission Bankruptcy, Central Vermont receives an additional .13%, or 921 KW, of the Phase I facility. CONSERVATION AND LOAD MANAGEMENT The primary purpose of Conservation and Load Management programs is to offset the need for long-term power supply and delivery resources that are more expensive to purchase or develop than customer-efficiency programs. For additional information regarding C&LM programs see PART II, Item 7, "Liquidity and Capital Resources" herein. The Company provides information to customers to help them use electricity more efficiently, first by ensuring that the customers are on the correct rate and have incorporated efficiency and conservation measures; secondly, by continually evaluating new energy management systems and other technologies to identify and develop programs to address new market opportunities and the competitive strengths of electricity. DIVERSIFICATION See PART II, Items 7 and 8 herein for information regarding the Company's diversification activities. The Company is continually assessing additional diversification opportunities. Any new investments will be financed primarily through a combination of debt and equity. EMPLOYEE INFORMATION A Local Union No. 300 affiliated with the International Brotherhood of Electrical Workers represents operating and maintenance employees of the Company and its wholly owned subsidiaries. At December 31, 1996 the Company and its wholly owned subsidiaries employed 637 persons, of which 230 are represented by the union. On December 31, 1992, the Company and its employees represented by the union agreed to a three-year contract, which provided for an annual wage increase of 3.95% for a three year period ending December 31, 1995. This contract expired on December 31, 1995, but it was extended until January 26, 1996, when a new three-year contract was agreed to by the Company and its employees represented by the Union. The new contract expires on December 31, 1998 and provides for general wage increases of 2.0%, 2.1% and 2.5% effective January 14, 1996, December 29, 1996 and December 28, 1997, respectively. Under the terms of the new agreement, effective in April 1996, Company's employees represented by the union will contribute weekly premiums for medical coverage of two, three and four dollars for the years 1996, 1997 and 1998, respectively. SEASONAL NATURE OF BUSINESS The Company experiences its heaviest loads in the colder months of the year. Winter recreational activities, longer hours of darkness and heating loads from cold weather usually cause the Company's peak of electric MWH sales to occur in January or late December. For additional information regarding the seasonal nature of business see PART II, Item 8 herein. Item 2. Properties. The Company. The Company's properties are operated as a single system which is interconnected by transmission lines of VELCO, New England Power Company and PSNH. The Company owns and operates 23 small generating stations with a total current nameplate capability of 70,070 KW, has a 1.78% joint-ownership interest in an oil generating plant in Maine, has a 20% joint-ownership interest in a wood, gas and oil-fired generating plant in Vermont, has a 1.73% joint-ownership interest in a nuclear generating plant in Connecticut and has a 46.08% joint-ownership interest in a transmission interconnection with Hydro-Quebec in Vermont. The electric transmission and distribution systems of the Company include about 613 miles of overhead transmission lines, about 7,257 miles of overhead distribution lines and about 235 miles of underground distribution lines which are located in Vermont except for about 23 miles of transmission lines which are located in New Hampshire and about two miles of transmission lines which are located in New York. Connecticut Valley. Connecticut Valley's electric properties consist of two principal systems in New Hampshire which are not interconnected with each other but each of which is connected directly with facilities of the Company. The electric systems of Connecticut Valley include about two miles of transmission lines and about 427 miles of overhead distribution lines and about 11 miles of underground distribution lines. All the principal plants and important units of the Company and its subsidiaries are held in fee. Transmission and distribution facilities which are not located in or over public highways are, with minor exceptions, located either on land owned in fee or pursuant to easements substantially all of which are perpetual. Transmission and distribution lines located in or over public highways are so located pursuant to authority conferred on public utilities by statute, subject to regulation of state or municipal authorities. VELCO. VELCO's properties consist of about 483 miles of high voltage overhead transmission lines and associated substations. The lines connect on the west at the Vermont-New York state line with the lines of Niagara Mohawk Power Corporation near Whitehall, New York, and Bennington, Vermont and with the submarine cable of NYPA near Plattsburg, New York; on the south and east with lines of New England Power Company and PSNH; on the south with the facilities of Vermont Yankee; and on the north with lines of Hydro-Quebec through a converter station and tie line jointly owned by the Company and several other Vermont utilities. VETCO. VETCO has approximately 52 miles of high voltage DC transmission line connecting at the Quebec-Vermont border in the Town of Norton, Vermont with the transmission line of Hydro-Quebec and connecting at the Vermont-New Hampshire border near New England Power Company's Moore hydro-electric generating station with the transmission line of New England Electric Transmission Corporation, a subsidiary of New England Electric System. Item 3. Legal Proceedings. On March 20, 1992, Sunnyside Cogeneration Associates filed suit in the United States District Court for the District of Vermont against the Company, CV Energy Resources, Inc. (CVER) and a subsidiary of CVER alleging damages in excess of five million dollars resulting from the parties' inability to come to agreement on the terms of CVER's proposed investment in the plaintiff's waste coal cogeneration facility under construction in Sunnyside, Utah. The Company filed an answer denying the allegations and both sides had filed motions for summary judgment which were denied. The plaintiff had also submitted its Requests for Finding of Fact, in which it claimed damages of approximately $8.7 million. The case was settled shortly before going to trial in early July 1996. On December 30, 1994, a lawsuit was filed in the United States District Court for the District of Vermont, Civil Action No. 2:94-CV386, by Bradford E. White, Michel J. Messier and John A. Wasik, against the Company, its present directors and certain former directors. This lawsuit (the "Shareholder Suit"), which purports to be on behalf of a class of consumers as well as on behalf of the Company's stockholders in enforcing the rights of the Company, alleged, among other things, (i) that F. Ray Keyser, Jr., Chairman of the Company's Board of Directors, violated Section 8 of the Clayton Act, 15 U.S.C. Subchapter 19, which precludes certain interlocking directorships, (ii) that Mr. Keyser violated his fiduciary duties to the Company's stockholders by acquiring and operating a series of businesses in competition with the Company without offering those business opportunities to the Company, (iii) that the remaining individual defendants violated their fiduciary duties to the Company's stockholders by failing to analyze, or to cause management to analyze, diversification into propane and fossil fuels, and by failing to make the Company an effective competitor of alternative fuel companies, and (iv) that the Company violated the applicable provision of the Vermont General Corporation Law by failing to provide a list of the Company's stockholders. The Shareholder Suit sought an unspecified amount of damages (including treble damages against Mr. Keyser), attorney's fees and costs, a list of the Company's stockholders, and a court order to enjoin the defendants from alleged continuing violations of the law. Each of the individual defendants and the Company itself denied the allegations against them and filed a Motion to Dismiss. In an Order dated September 20, 1996, the U.S. District Court Judge dismissed all of the claims filed against the Company and its directors. Information regarding the Company's advancement of expenses incurred by the Company's directors in connection with the Shareholder Suit is set forth in PART III, Item 13 under the captions "Report of Indemnification and Advancement of Expenses" and "Compensation Committee Interlocks and Insider Participation" incorporated herein by reference. On July 29, 1996, the Company filed a Declaratory Judgment action in the United States District Court for the District of Vermont. The Complaint names as defendants a number of insurance companies that issued policies to the Company dating from the mid 1940s to the late 1980s. The Company asserts that policies issued by defendants provide coverage for all defense and remediation costs associated with the Cleveland Avenue property, the Bennington Landfill site and the North Clarendon site. With the exception of the North Clarendon site where no further remediation is anticipated, see PART II, Item 8 "Environmental" for related disclosures. There are no other material pending legal proceedings, other than ordinary routine litigation incidental to the business, to which the Company or any of its subsidiaries is a party or to which any of their property is subject. Item 4. Submission of Matters to a Vote of Security Holders. There were no matters submitted to security holders during the fourth quarter of 1996. PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters. (a) The Company's common stock is traded on the New York Stock Exchange (NYSE) under the trading symbol CV. The table below shows the high and low sales price of the Company's common stock, as reported on the NYSE composite tape by The Wall Street Journal, for each quarterly period during the last two years as follows: Market Price High Low -------- -------- 1996 First quarter.............. $ 15 1/8 $ 13 1/4 Second quarter............. 15 1/8 12 Third quarter.............. 13 5/8 12 Fourth quarter............. 13 12 1995 First quarter.............. $ 14 1/4 $ 13 1/4 Second quarter............. 14 1/4 13 1/4 Third quarter.............. 14 3/8 13 3/8 Fourth quarter............. 14 3/8 13 1/4 (b) As of December 31, 1996, there were 14,740 holders of the Company's common stock, $6 par value. Common stock dividends have been declared quarterly. Cash dividends of $.20 per share were paid for all quarters of 1995. Cash dividends of $.20 per share were paid for the first two quarters of 1996 and cash dividends of $.22 per share were paid for the last two quarters of 1996. So long as any Senior Preferred Stock or Second Preferred Stock is outstanding, except as otherwise authorized by vote of two-thirds of each such class, if the Common Stock Equity (as defined) is, or by the declaration of any dividend will be, less than 20% of Total Capitalization (as defined), dividends on Common Stock (including all distributions thereon and acquisitions thereof), other than dividends payable in Common Stock, during the year ending on the date of such dividend declaration, shall be limited to 50% of the Net Income Available for Dividends on Common Stock (as defined) for that year; and if the Common Stock Equity is, or by the declaration of any dividend will be, from 20% to 25% of Total Capitalization, such dividends on Common Stock during the year ending on the date of such dividend declaration shall be limited to 75% of the Net Income Available for Dividends on Common Stock for that year. The defined terms identified above are used herein in the sense as defined in subdivision 8A of the Company's Articles of Association; such definitions are based upon the unconsolidated financial statements of the Company. As of December 31, 1996, the Common Stock Equity of the Company was 57.4% of total capitalization. For additional information regarding dividend payment level and dividend restrictions see Item 8 herein.
Item 6. Selected Financial Data. (Dollars in thousands, except per share amounts) 1996 1995 1994 1993 1992 For the year Operating revenues $290,801 $288,277 $277,158 $279,389 $275,375 Net income* $ 19,442 $ 19,851 $ 14,800 $ 21,292 $ 21,422 Earnings available for common stock* $ 17,414 $ 17,823 $ 12,662 $ 18,634 $ 18,764 Consolidated return on average common stock equity* 9.4% 10.0% 7.2% 11.0% 11.8% Earnings per share of common stock* $1.51 $1.53 $1.08 $1.64 $1.71 Cash dividends paid per share of common stock $.84 $.80 $1.42 $1.42 $1.39 Book value per share of common stock $16.19 $15.51 $14.56 $15.03 $14.21 Net cash provided by operating activities $ 42,688 $ 41,711 $ 49,426 $ 36,833 $ 48,904 Dividends paid $ 11,728 $ 11,350 $ 18,845 $ 18,112 $ 18,174 Construction and plant expenditures $ 18,952 $ 21,337 $ 22,621 $ 20,519 $ 20,503 Deferred conservation and load management expenditures $ 1,589 $ 3,899 $ 6,159 $ 9,874 $ 3,539 At end of year Long-term debt $117,374 $119,142 $120,157 $122,419 $107,879 Long-term lease arrangements $ 18,304 $ 19,385 $ 20,467 $ 21,553 $ 22,641 Redeemable preferred stock $ 20,000 $ 20,000 $ 20,000 $ 20,000 $ 20,000 Total capitalization (excluding current portion of debt) $350,201 $346,341 $339,462 $352,862 $324,664 Total assets $502,968 $489,213 $489,570 $479,373 $451,026 * After deducting non-recurring charge-offs (net of taxes) of $1,703 ($.15 per share) and $4,336 ($.37 per share) for 1995 and 1994, respectively; and reflecting a gain from insurance proceeds and other charges (net of taxes) of $1,300 ($.11 per share) and the Appomattox gain (net of taxes) of $905 ($.08 per share) for 1996 and 1995, respectively.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Earnings Overview. The Company's 1996 net income was $19.4 million or $1.51 per share of common stock, which equates to a 9.4% return on average common equity. Net income and earnings per share of common stock for 1996 compare to $19.9 million and $1.53 in 1995, and $14.8 million and $1.08 in 1994. The return on average common equity was 10.0% for 1995 and 7.2% for 1994. For 1996, net income and earnings per share of common stock for the Company's utility business were reduced by approximately $3.7 million and $.32, respectively, for unscheduled incremental nuclear outage costs and related replacement power costs. This reduction was offset by the 5.5% retail rate increase effective June 1, 1996 and insurance proceeds of approximately $1.3 million or $.11 per common share. Non-utility net income and earnings per share of common stock for 1996 were reduced by approximately $1.4 million and $.12, respectively, for expenses incurred in connection with a project currently under development by the Company's wholly owned subsidiary, Catamount Energy Corporation (Catamount). These expenses would be reimbursed if this pending project reaches financial closing. As part of Vermont's industry restructuring effort, the Company is working toward a Memorandum of Understanding (MOU) between Vermont's largest utilities and the Vermont Department of Public Service (DPS). The terms of the MOU, which are subject to Vermont's legislative and regulatory processes before it can become effective, are described below in Liquidity and Capital Resources - Electric Industry Restructuring. On April 30, 1996, the Company received a rate order from the Vermont Public Service Board (PSB). The PSB order generally approved an agreement reached with the DPS that provided for a 5.5% increase in Vermont retail rates effective with bills rendered on June 1, 1996 and an additional 2% increase effective January 1, 1997. Combined, these rate increases produce annualized revenues of approximately $16 million. The PSB order also caps the Company's allowed return on common equity in its Vermont retail business at 11% for 1996 and 1997. For additional information see Rates and Regulation below. Earnings for 1995 reflect a $.15 per common share charge pursuant to a PSB Accounting Order requiring a write-off of 1994 restructuring costs, an $.08 per share gain on the sale by Catamount of approximately half of its limited partnership interest in the Appomattox Cogeneration project, the 5.07% retail rate increase effective November 1, 1994 and increased retail sales. The 1994 net income and earnings per share of common stock were reduced by approximately $4.3 million and $.37, respectively, for three non-recurring charges resulting from 1) cost disallowances associated with a PSB Rate Order which reduced after-tax earnings and earnings per share of common stock by approximately $1.8 million and $.16, respectively; 2) the Company's decision to discontinue its proposed new headquarters office building which reduced after-tax earnings and earnings per share of common stock by $1.7 million and $.14, respectively; and 3) writing down SmartEnergy Services, Inc.'s investment in Green Technologies, Inc.'s (Green Technologies) common stock to reflect management's estimate in the decline in value of the investment which reduced after-tax earnings and earnings per share of common stock by $.8 million and $.07, respectively. In 1996 the Company earned an 11.0% return on average common equity on its Vermont utility business and a 2.5% return on non-utility investments. The Company's consolidated return on average common equity in 1996 was 9.4%. See Note 3 to the Consolidated Financial Statements for additional details on the Company's non-utility investments. Results of Operations. The major elements of the Consolidated Statement of Income are discussed below. Operating revenues and megawatt-hour (MWH) sales A summary of MWH sales and operating revenues for 1996 and 1995 (and the related percentage changes from 1995) is set forth below:
Percentage Percentage MWH Sales Increase Revenues (000's) Increase 1996 1995 (Decrease) 1996 1995 (Decrease) ---- ---- ---------- ---- ---- ---------- Residential 957,733 946,342 1.2 $108,603 $103,365 5.1 Commercial 900,590 876,735 2.7 98,890 93,950 5.3 Industrial 401,781 404,487 (.7) 32,399 31,565 2.6 Other retail 7,229 7,361 (1.8) 1,856 1,794 3.5 --------- --------- -------- -------- Total retail sales 2,267,333 2,234,925 1.5 241,748 230,674 4.8 --------- --------- -------- -------- Resale sales: Firm 1,717 4,860 (64.7) 81 223 (63.7) Entitlement 470,760 895,409 (47.4) 24,781 39,802 (37.7) Other 770,542 580,048 32.8 18,705 13,269 41.0 --------- --------- -------- -------- Total resale sales 1,243,019 1,480,317 (16.0) 43,567 53,294 (18.3) --------- --------- -------- -------- Other revenues - - 5,486 4,309 27.3 --------- --------- -------- -------- Total 3,510,352 3,715,242 (5.5) $290,801 $288,277 .9 ========= ========= ======== ========
Year-to-year fluctuations in total retail MWH sales are primarily affected by customer growth, Conservation and Load Management (C&LM) programs, as well as relative prices of alternate energy sources, weather patterns and conservation induced by price changes and income elasticity responses of customers. Retail MWH sales for 1996 increased 1.5% compared to 1995. Retail revenues increased $11.1 million or 4.8% over last year due to a $7.5 million increase in revenues resulting from the 5.5% retail rate increase effective June 1, 1996 and $3.6 million associated with a 1.5% increase in retail MWH sales. Residential and commercial MWH sales increased 1.2% and 2.7%, respectively, reflecting the normal cold weather experienced during the first quarter of 1996 while industrial MWH sales decreased .7% as a result of increased natural snow fall during 1996 reducing ski areas' megawatt-hour requirements for snow making. Total retail MWH sales for 1995 increased .9% compared to 1994. Retail MWH sales declined during the first quarter of 1995 due to warm weather and its impact on winter recreational activities. However, retail MWH sales improved throughout the remainder of the year. Retail revenues for 1995 increased $9.7 million or 4.4% over 1994 due to an $8.0 million increase in revenues resulting from the 5.07% retail rate increase effective November 1, 1994 and $1.8 million associated with a .9% increase in MWH sales. Due to current market conditions, some of the Company's firm resale customers chose not to extend their contracts. As a result, firm resale MWH sales and revenues declined for 1996 and 1995. The decrease in entitlement MWH sales and revenues for 1996 is primarily due to the expiration, in October 1995, of a five year sale of part of the Company's interest in the output of Vermont Yankee and Merrimack #2 and lower sellback of Hydro-Quebec power. For 1995, entitlement MWH sales and revenues increased 7.3% and 6.9%, respectively, due to the sale of power purchased from Hydro-Quebec to Boston Edison Company. However, this increase was partially offset by decreased MWH sales made in conjunction with a swap arrangement with Commonwealth Electric Company, which terminated on October 31, 1995, reduced sell-backs to Hydro-Quebec of purchased power and reduced sales to UNITIL Power Corp. due to the scheduled refueling and maintenance shutdown of Vermont Yankee that began on March 17, 1995. Other resale sales and revenues increased 32.8% and 41.0%, respectively, compared to 1995 resulting from increased system capacity sales and sales to New England Power Pool (NEPOOL) offset by a decrease in unit and off-system sales. Other resale sales for 1995 decreased 62,754 MWH and related revenues decreased $.9 million, primarily from lower short-term sales to NEPOOL. Other revenues for 1996 increased due to an increase in transmission revenues related to a transmission interconnection agreement. The Company continues to make every effort to maintain or increase resale sales despite the weak market for capacity and energy in the region. The table below analyzes the components of increases or decreases in revenues compared to the prior year (dollars in thousands): 1996 1995 Revenue increase (decrease) from: Retail MWH sales $ 3,557 $ 1,765 Retail rates 7,517 7,963 Changes in firm resale sales (142) (411) Changes in entitlement sales (15,021) 2,582 Changes in other resale sales 5,436 (932) Changes in other revenues 1,177 152 ------- ------- Net increase over prior year $ 2,524 $11,119 ======= ======= Purchased power The Company purchases approximately 90% of its power needs under several contracts of varying duration. Over 30% of these purchases are from affiliated companies whereby the Company receives its entitlement share of the output. The Company's purchased power portfolio assures that a diversified mix of sources and fuel types are available to meet the Company's long-term load growth while providing short and intermediate term opportunities to purchase or sell capacity and energy to reduce overall power costs. A breakdown of the Company's energy sources is shown below: Year Ended December 31 1996 1995 1994 Nuclear generating companies 36% 32% 39% Canadian imports 30 33 20 PSNH--coal 8 8 7 Company-owned hydro 6 4 5 Jointly owned units 2 4 5 Small power producers 6 5 5 Other sources 12 14 19 --- --- --- 100% 100% 100% === === === The Company maintains a 1.7303% joint-ownership interest in Millstone Unit #3 (Unit #3) of the Millstone Nuclear Power Station and owns a 2% equity interest in Connecticut Yankee. These two plants are operated by Northeast Utilities (NU). The Company also maintains joint-ownership interests in Joseph C. McNeil, a 53 MW wood, gas and oil-fired unit and Wyman #4, a 619 MW oil-fired unit and owns a 31.3%, 2% and 3.5% equity interest in Vermont Yankee, Maine Yankee and Yankee Atomic, respectively. In addition, the Company owns 20 hydroelectric generating units with a total nameplate capability of 41.2 MW and two gas-fired and one diesel-peaking units with a combined nameplate capability of 28.9 MW. On January 31, 1996, the Nuclear Regulatory Commission (NRC) placed the Millstone Nuclear Power Station on its "watch list." On March 30, 1996, NU decided to shut down Unit #3 following an engineering evaluation which determined that four safety-related valves would not be able to perform their design function during certain assumed events. In July 1996, NU reported that on July 2, 1996, Northeast Utilities Service Company (NUSCO) filed an extensive document with the NRC responding to a series of requests from the NRC seeking assurance that Unit #3 will be operated in accordance with the terms of its operating license and other NRC requirements and regulations and also dealing with a series of issues that NU has identified in the course of these reviews. The document also included an Operational Readiness Plan for Unit #3 which is currently under review by the NRC. On August 14, 1996, an independent review team was created by the NRC to review actions to be taken by NU prior to the restart of Unit #3. On October 18, 1996, the NRC informed NU that it will establish a Special Projects Office to oversee inspection and licensing activities at Millstone. The Special Projects Office will be responsible for 1) licensing and inspection activities at NU's nuclear units, 2) oversight of an 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 nuclear units' restart activities. On October 24, 1996, the NRC issued an order requiring NU to devise and implement a comprehensive plan for handling safety concerns raised by Millstone Nuclear Power Station employees for ensuring an environment free from retaliation and discrimination and to retain an independent third-party to monitor and review NU's performance in handling employee concerns. NU's management has indicated it cannot presently estimate the timing of the restart of Unit #3 or what additional costs, if any, will be incurred. The Company remains actively involved with the other non-operating minority joint-owners of Unit #3. This group is engaged in various activities to monitor and evaluate NU/NUSCO's efforts relating to Unit #3. In addition, this group has retained counsel and experts to review and evaluate NU/NUSCO's operation and management and any prospective claims the group members may be able to assert against NU/NUSCO or related companies. The Company estimates that while Unit #3 is out of service it will incur incremental replacement power costs estimated at $250,000 to $350,000 per month. In addition, the Company incurred incremental operation and maintenance costs during 1996 of about $1.8 million. This amount includes $.5 million representing an estimate of the Company's share of additional costs NU expects to incur in 1997 to return Unit #3 to service. In July 1996, the Connecticut Yankee Nuclear Power Plant was shut-down due to several issues related to certain containment air recirculation and service water systems. On December 4, 1996, the Board of Directors of Connecticut Yankee Atomic Power Company (CYAPC) voted to retire the plant from commercial operation. The decision to shutdown the plant was based on an economic evaluation of the costs of operating it compared to the costs of closing it and incurring replacement power costs over the remaining period of the plant's operating license. CYAPC has undertaken various regulatory filings intended to implement the decommissioning of the plant. For additional information relating to the permanent shutdown of Connecticut Yankee Nuclear Power plant, see Note 2 to the Consolidated Financial Statements. The Vermont Yankee Nuclear Power plant, which provides approximately one-third of the Company's power supply, had scheduled refueling outages from September 7 through November 5, 1996 and from March 17 through May 2, 1995. For information in regard to Vermont Yankee's Design Basis Documentation project, the cold shutdown configuration and unscheduled outages of Maine Yankee, and the permanent shutdown of Yankee Atomic, see Note 2 to the Consolidated Financial Statements. During scheduled refueling outages, the Company purchases more costly replacement energy from other sources to satisfy energy needs. In accordance with current rate-making treatment, the Company defers and amortizes to expense over their respective fuel cycles the incremental replacement energy and maintenance costs associated with refueling outages for the Yankee plants and Unit #3 jointly owned nuclear generating unit. During 1996, the Company deferred $1.5 million and $6.0 million of replacement energy and capacity costs, respectively, for Vermont Yankee and for 1995 deferred $2.4 million and $6.9 million of replacement energy and capacity costs, respectively, for Vermont Yankee, Maine Yankee, Connecticut Yankee and Unit #3. Under various long-term purchase power contracts expiring in 2016, the Company receives varying amounts of capacity and energy from Hydro-Quebec. See Note 13 to the Consolidated Financial Statements for further details related to the Hydro-Quebec power contracts. Under a 30-year contract, which expires in 1998, the Company, through Vermont Electric Power Company, Inc., purchases 46.98 MW of capacity from Merrimack #2, a coal-fired generating plant owned by NU. The Company, under long-term contracts, purchases power from a number of small power producers who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy using hydroelectric, wood, biomass and refuse-burning generation. During 1996, the Company purchased 219,584 MWH of which approximately 159,064 MWH is associated with the Vermont Electric Power Producers and 37,203 MWH with a New Hampshire/Vermont solid waste plant. The Company engages in purchases and sales with other electric utilities and with NEPOOL to take advantage of immediate pricing and other market conditions. These purchases are included in Other sources in the table above. The net cost components of purchased power and production fuel costs for the past three years were as follows (dollars in thousands):
1996 1995 1994 Units Amount Units Amount Units Amount Purchased and produced: Capacity (MW) 526 $ 86,431 585 $ 85,758 568 $ 83,677 Energy (MWH) 3,445,259 67,991 3,603,446 63,907 3,544,563 59,485 -------- -------- -------- Total purchased power costs 154,422 149,665 143,162 Production fuel (MWH) 295,802 1,570 348,528 2,358 381,819 1,932 -------- -------- -------- Total purchased power and production fuel costs 155,992 152,023 145,094 Entitlement and other resale sales (MWH) 1,241,302 43,486 1,475,457 53,071 1,477,106 51,421 -------- -------- -------- Net purchased power and production fuel costs $112,506 $ 98,952 $ 93,673 ======== ======== ========
The increase in purchased capacity cost of $.7 million for 1996 over 1995 resulted from $9.3 million in higher prices offset by a 10%, or $8.6 million, decrease in the amount of MW purchased. Purchased capacity costs increased $2.1 million for 1995 over 1994 resulting from a 3%, or $2.5 million, increase in the amount of MW purchased offset by lower prices of approximately $.4 million. Energy costs are directly related to the variable prices of oil, nuclear fuel and coal but, more importantly, to the proportion of the Company's purchased energy that comes from each of these fuel sources. The increase in energy costs for 1996 resulted from an 11% or $6.9 million increase in cost per MWH purchased offset by a 4.4% or $2.8 million decrease in the amount of MWH purchased. The price increase results primarily from incremental replacement power costs associated with Unit #3 discussed above. In total, energy costs for 1995 over 1994 increased $4.4 million. Cost per MWH purchased increased 5.7% or $3.4 million and the amount of MWH purchased increased 1.7% or $1.0 million. The Company is responsible for paying its entitlement percentage of decommissioning costs for Vermont Yankee, Connecticut Yankee, Maine Yankee and Yankee Atomic as well as its joint ownership percentage of decommissioning costs for Unit #3. See Notes 2 and 13 to the Consolidated Financial Statements. Recently, the staff of the Securities and Exchange Commission has questioned certain current accounting practices of the electric utility industry, including the Company, regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in financial statements of electric utilities. In response to these questions, the Financial Accounting Standards Board has agreed to review the industry-wide accounting for nuclear decommissioning costs. If current electric utility industry accounting practices for such decommissioning costs are changed, it is possible that annual expense provisions for decommissioning costs could increase, the total estimated costs for decommissioning could be recorded as a liability, and income from external decommissioning trusts could be reported as investment income instead of a reduction to decommissioning expense. The Company does not believe that such changes, if required, would have an adverse effect on results of operations due to its ability to recover decommissioning costs through the regulatory process. See Liquidity and Capital Resources - Competition, for related information. Production fuel costs decreased $.8 million for 1996 due primarily to lower generation by Unit #3 discussed above. For 1995 production fuel costs increased over 1994 by $.4 million due to an increase in price of approximately $.7 million offset by an 8.8% decrease in the amount of MWH generated primarily by Unit #3, due to its scheduled refueling outage. In order to optimize its power mix for baseload, intermediate and peaking power, the Company engages in sales and purchases with other electric utilities, primarily in New England and with NEPOOL. The profits from these transactions are used to reduce purchased power costs. Based on present commitments and contracts, the Company expects that net purchased power and production fuel costs will be approximately $125.3 million, $133.7 million and $133.4 million for the period 1997 through 1999. Other operation expenses In accordance with a PSB Accounting Order issued in January 1996, the Company expensed, in December 1995, approximately $2.9 million of deferred restructuring costs. This recognition combined with reduced amortization of about $.8 million for 1996, decreased other operation expenses approximately 9.5% compared to 1995. Other operation expenses for 1995 were relatively flat compared to 1994. Maintenance expenses The $2.1 million or 15.9% increase in maintenance expenses for 1996 compared to 1995 is primarily attributable to nuclear maintenance expenses associated with the Company's joint ownership interest in Unit #3 discussed above. Income taxes Federal and state income taxes fluctuate with the level of pre-tax earnings. These taxes decreased for 1996 as a result of lower pre-tax earnings and increased for 1995 as a result of higher pre-tax earnings. Other income and deductions Equity in earnings of affiliates for 1996 were about the same as 1995 and increased 6.3% for 1995 compared to 1994 resulting from higher earnings from the Company's nuclear generating affiliates. The increase in allowance for equity and borrowed funds used during construction for 1996 is due to a higher level of construction expenditures and higher rates used for capitalization of these funds. The decrease in other income (expenses), net for 1996 compared to 1995 is primarily due to approximately $2.3 million of expenses incurred in connection with a non-utility project currently under development in Summersville, West Virginia. These expenses would be reimbursed if this pending project reaches financial closing. The decrease was offset by insurance proceeds of $1.3 million recorded in the first quarter of 1996, higher income from Catamount's operating investments and an increase in interest and dividend income. For 1995, the increase in other income (expenses), net results primarily from the 1995 $1.5 million pre-tax gain on the sale of a partial interest in the Appomattox project and the 1994 $1.3 million write-down of the Company's investment in Green Technologies. However, the increase was partially offset by a $.4 million additional write-off of the Company's investment in Green Technologies in 1995 to reflect management's estimate of the permanent decline in the value of the investment. Other interest expense Other interest expenses declined for 1996 due to lower average interest rates combined with decreased short-term debt levels. Due to increased short-term debt levels and higher interest rates, other interest expense increased for 1995 compared to 1994. Cash Dividends Declared Preferred In January 1994, the Company redeemed 280,000 shares of preferred stock 9% dividend series at a premium of $.25 per share. This redemption resulted in a decrease in preferred dividends declared for 1995. Common The increase in common dividends declared for 1996 results from a 10% increase in the quarterly common dividend paid (from $.20 to $.22 per share) on the Company's outstanding common stock in August and November 1996. The decrease in common dividends declared for 1995 results from an advanced quarterly common dividend declaration in December 1994 payable February 15, 1995. As a result, the accompanying Consolidated Financial Statements reflect three quarterly dividend declarations in 1995 and five in 1994. The December 1994 declaration reflected the 44% reduction in quarterly dividend rate per share (from $.355 to $.20 per share) discussed below. Liquidity and Capital Resources Construction The Company's liquidity is primarily affected by the level of cash generated from operations and the funding requirements of its ongoing construction and C&LM programs. Net cash provided by operating activities generated $42.7 million in 1996, $41.7 million in 1995 and $49.4 million in 1994. The Company ended the 1996 year with cash and cash equivalents of $6.4 million, a decrease of $5.6 million from the beginning of the year. The decrease in cash for 1996 was the result of $42.7 million provided by operating activities, $28.0 million used for investing activities and $20.3 million used for financing activities. Operating Activities Approximately $37.5 million of cash was provided from net income before non-cash items, primarily depreciation. About $5.2 million of cash was provided from fluctuations in working capital and other operating activities, including C&LM programs, restructuring costs, gain on sale of property and net deferral/amortization of nuclear replacement energy and maintenance costs. Investing Activities Construction and plant expenditures consumed approximately $19.0 million, $1.6 million was used for C&LM programs, $2.9 million was used for non-utility investments, $5.2 million was deposited in an escrow account to fund non-utility investments, $.3 million was used for the rental water heating program while $1.0 million was provided by sales of property. Financing Activities Dividends paid on common stock were $9.7 million, while preferred stock dividends were $2.0 million. Quarterly dividends paid on common stock in August and November 1996 reflected the 10% increase from the 1995 level. Long-term debt borrowings provided $1.2 million while short-term obligations, retirement of long-term debt and the repurchase of common stock required $7.7 million, $1.0 million and $1.1 million, respectively. Excluding allowance for funds used during construction, construction expenditures are estimated at $17.5 million, $21.4 million and $16.2 million for the years 1997 through 1999, respectively. These spending levels are consistent with the Company's goal to move toward limiting annual capital expenditures to annual depreciation. Electric Industry Restructuring The electric utility industry is in a period of transition that may result in a shift away from franchised monopoly service, and cost of service and return on equity based rates to one with more competition and market based rates at least for the power supply portion of electric service. Most states, including Vermont and New Hampshire, where the Company does business, are exploring new mechanisms to bring greater competition, customer choice, direct retail access and market influence to the industry while retaining the public benefits associated with the current regulatory system. Vermont In Vermont, the PSB by Order dated October 17, 1995, opened a process requiring all 22 electric utilities in Vermont to file proposed restructuring plans by mid-1996. The goal, as set forth in the Order, is to achieve restructuring by January 1, 1998. The Company filed its electric industry restructuring proposal with the PSB on June 19, 1996. Pursuant to the Company's proposal, incumbent electric utilities would be required to functionally separate their power production and sales functions from their regulated distribution and transmission functions. A restructuring of the electric utility industry could result in stranded costs for incumbent utilities. Stranded costs are that portion of utility investments and obligations made for public service purposes that cannot be recovered because of restructuring. The Company's restructuring proposal described the basis for the Company's assertion that it is entitled to recover its stranded costs should Vermont pursue the restructuring of the utility industry. On December 31, 1996, the PSB issued a Report and Order (the Report) outlining a restructuring plan (Plan) for the Vermont electric utility industry requiring legislative approval. The Plan consists of nine components as follows: Provide customer choice. Enable all customers to demand and purchase the products and service they need and want. It provides for additional market opportunities for low-usage customers. Require Vermont's largest investor-owned utilities to divide their generation and distribution functions into separate corporate subsidiaries. The PSB does not propose full corporate divestiture at this time but requires this "functional separation" of the companies into wholly owned subsidiaries. Provide for equitable treatment of stranded costs. It promotes aggressive actions to reduce utilities' current and future costs and provides utilities with the opportunity to recover their legitimate, remaining stranded costs. Address the unique attributes of municipal, cooperative, and small investor- owned utilities. The Plan requires that these utilities provide open access to competitive providers, but does not require functional separation of activities. Assure consumer protection. Preserves the wide range of consumer protections currently provided by the franchise system. It proposes new initiatives to assist low-income customers. Deliver cost-effective energy efficiency programs to all customers. It proposes several complimentary approaches to delivering energy efficiency to Vermont's electric consumers. Promote the continued use and development of renewable energy resources. Requires all retail companies selling electricity in Vermont to secure a minimum percentage of the sales from renewable resources. Promote national and regional policies that assure environmental quality. The Plan supports proposals in neighboring states to impose environmental comparability on older generation sources and the creation of an inter-regional emissions trading program. Establish a regional independent system operator (ISO) and power exchange. The Plan proposes the establishment of a regional power exchange to provide a short-term spot market for energy services and other services necessary to support system reliability by the ISO. The Report also indicated that the implementation date could be as late as the end of 1998. Note that the Report does not constitute a final, binding order but is instead a recommendation to the Vermont Legislature. If adopted by the Vermont Legislature, the Plan would allow for the recovery of stranded costs through a non-bypassable, non-discriminatory wires charge on electric consumption, after mitigation of costs. It would also authorize the use of incentive-and performance-based regulation for distribution companies presently subject to price regulation. The Report promotes aggressive actions to reduce utilities' current and future power costs including "innovative financing renegotiation of above-market contractual commitments, and asset sales." If adopted by the Vermont Legislature, the PSB would take into account the circumstances under which stranded costs were incurred and the companies' efforts to mitigate them. The multiple step process outlined by the PSB would involve 1) an estimation of stranded costs including an estimation of future power costs and a determination of the extent to which stranded costs can be mitigated, 2) an adjustment of stranded costs and 3) a stranded cost reconciliation proceeding. The largest component of the Company's stranded costs are future costs under long-term purchased power contracts. If the PSB's recommendation is approved by the Vermont Legislature, the Company will be able to recover its unmitigatable stranded costs through a non-bypassable, non-discriminatory wires charge on electric consumption. The Report suggests that if utilities satisfy a multi-factor analysis, Vermont should "create the opportunity for full recovery of stranded costs provided they are legitimate, verifiable, otherwise recoverable, prudently incurred and non-mitigatable." Such recover is, however, "explicitly tied to successful mitigation." At this time, the Company cannot give assurance that it will be successful in realizing mitigation of these costs to the extent that will satisfy the broad standards identified by the PSB or that it will be able to achieve full or substantial recovery of these costs, should Vermont's utility industry be restructured. The PSB Report "strongly encourage[s] the participants in this docket to continue to work together to forge comprehensive solutions on a consensus basis wherever possible." The Company continues to work to achieve a restructured industry in Vermont which meets the consensus principles for industry restructuring endorsed by the PSB and protects the interests of the Company and the stakeholders who financed the system under the regulatory bargain. In an effort to achieve a negotiated resolution to the issues surrounding the restructuring of the Vermont electric utility industry, the Company, Green Mountain Power Corporation, the DPS and representatives of the Governor of Vermont are currently developing a Memorandum of Understanding (MOU) which would establish a known plan for implementing restructuring in Vermont. If the concepts developed pursuant to the MOU to date are implemented, it is anticipated that the impact would: Result in a decrease in Vermont-related total electricity prices for 1998 and 1999 and reduce future total electric prices from what they would have been absent restructuring in Vermont, under all reasonable market price scenarios. Allow retention of all utility business segments, including generation and distribution, through functional separation into separate legal affiliates. Pre-define the level of, timing for and measurement of mitigation and, if such mitigation is accomplished, provide for substantial certainty for collecting the remainder of the Company's Vermont jurisdictional stranded costs. To achieve this certainty, it is anticipated that the Company would have to achieve mitigation of its stranded costs of at least $133 million (on a net present value basis) by December 31, 2001. Set up a mechanism to collect stranded costs through a non-bypassable Competitive Transition Charge. Establish a grantor trust financing mechanism to fund stranded cost mitigation or to fund the under collection of stranded costs. Fix a distribution company price path through 2004. Given the complexity of the MOU and the uncertainty surrounding necessary legislative action to implement it, the Company cannot predict when or if the provisions of the MOU would become effective and thus change the current regulatory process in Vermont. Restructuring proposals are presently under consideration by the Vermont General Assembly that would provide for the restructuring of Vermont's electric utility system. At this time, it cannot be determined whether any restructuring legislation will be enacted, or if enacted, whether it will conform to the concepts developed by the Report or through the MOU. New Hampshire In New Hampshire, the New Hampshire Public Utilities Commission (NHPUC), directed by the New Hampshire legislature, has established a Pilot Program (Pilot) to determine the implications of retail competition in the electric utility industry. The Pilot is for a two-year period beginning in May 1996 and is open to all electric utilities and to 3% of all classes of customers in New Hampshire. The Company competed as a competitive supplier to acquire additional load currently served by other New Hampshire utilities and to retain load currently served by Connecticut Valley Electric Company Inc. (Connecticut Valley), the Company's wholly owned New Hampshire subsidiary. The Company acquired new customers with combined annual electric use totaling approximately 20 million kilowatt hours. On September 10, 1996, pursuant to legislation enacted in May 1996, the NHPUC issued a preliminary plan to restructure the electric industry in New Hampshire including Connecticut Valley. The legislation requires generation to be functionally separated from transmission and distribution, with the distribution and customer-related services remaining subject to regulation by the NHPUC. The Plan calls for New Hampshire utilities to unbundle their electric rates and services into generation, transmission, distribution and Conservation and Load Management services. It provides for an interim stranded cost charge effective for two years following the implementation of the New Hampshire utilities compliance filings. The NHPUC plans to implement retail choice for all customers by January 1, 1998 and in no event later than June 30, 1998. Connecticut Valley and other parties provided written and oral comments to the NHPUC on its Plan. This input includes proposals for restructuring by consultants retained by the NHPUC. In particular, a proposal by LaCapra and Associates would cap Connecticut Valley's retail rates at a regional level upon the event of retail choice in Connecticut Valley's service territory. If adopted, this proposal could result in stranded costs of up to $38 million (on a net present value basis) related to purchased power contracts based on LaCapra and Associates' estimate. Connecticut Valley constituted approximately 7% of the Company's total retail MWH sales for the year ended December 31, 1996. Ultimately, the financial impacts of restructuring on Connecticut Valley and the Company may be determined by the FERC and the courts. The FERC regulates the wholesale power sale from the Company to Connecticut Valley. Should the State of New Hampshire require the termination of that sale, the Company expects that the FERC would determine the recovery of any lost net revenues going forward. The Company may also have legally protected rights which could be enforced in proceedings in the New Hampshire, Vermont and Federal judicial systems. For additional information related to the NHPUC Plan see Note 17, Subsequent Event, to the Consolidated Financial Statements. Competition-Risk Factors If retail competition is implemented in Vermont or New Hampshire, the Company is unable to predict the impact of this competition on its revenues, the Company's ability to retain existing customers and attract new customers or the margins that will be realized on retail sales of electricity. Historically, electric utility rates have been based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," requires regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, and thereby defer the income statement impact of certain costs and revenues that are expected to be realized in future rates. As described in PART II, Item 8, Note 1 to the Notes to Consolidated Financial Statements, the Company complies with the provisions of SFAS No. 71. In the event the Company determines that it no longer meets the criteria for following SFAS No. 71, the accounting impact would be an extraordinary, non-cash charge to operations of an amount that could be material. Criteria that give rise to the discontinuance of SFAS No. 71 include (1) increasing competition that restricts the Company's ability to establish prices to recover specific costs and (2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and for Long-Lived Assets to Be Disposed Of," which was implemented by the Company on January 1, 1996, requires that any assets, including regulatory assets, that are no longer probable of recovery through future revenues, be revalued based upon future cash flows. SFAS No. 121 requires that a rate-regulated enterprise recognize an impairment loss for the amount of costs excluded from recovery. As of December 31, 1996, based upon the regulatory environment within which the Company currently operates, SFAS No. 121 did not have an impact on the Company's financial position or results of operations. Competitive influences or regulatory developments may impact this status in the future. The Company believes that the provisions of both the Report and MOU, if approved by the PSB and Vermont General Assembly, would meet the criteria for continuing application of SFAS Nos. 71 and 121. Because the Company is unable to predict what form enacted legislation will take, however, it cannot predict if or to what extent SFAS Nos. 71 and 121 will continue to be applicable in the future. As such, the Company cannot predict whether the Report, the MOU and restructuring legislation enacted in Vermont or the issuance of a final restructuring Plan in New Hampshire would have a material adverse effect on the Company's operations, financial condition or credit ratings. However, the Company's failure to recover a significant portion of its purchased power costs, would likely have a material adverse effect on the Company's results of operations, cash flows and ability to obtain capital at competitive rates. It is possible that stranded cost exposure before mitigation could exceed the Company's current total common stock equity. Other In order to strengthen the Company's competitiveness and responding to current and anticipated changes in the electric utility industry, the Company's board of directors (Board) and management decided to align the Company into five strategic business units (SBUs). These SBUs, designed to provide business focus required to sustain financial viability in the changing electric utility industry, will also create growing and discernible value for the Company's employees, customers and shareholders. In addition, the formation of these SBUs will allow the Company to unbundle its functions more easily during the transition to deregulation. Financing and Capitalization Utility The level of short-term borrowings fluctuates based on seasonal corporate needs, the timing of long-term financings and market conditions. Short-term borrowings are supported by committed lines of credit and uncommitted loan facilities with several banks totaling $37.25 million. In the past, the Company has been able to finance its construction and C&LM programs out of net-cash generated by operating activities and it expects to meet future commitments in the same manner. On June 3, 1996, the Company's Board increased the quarterly dividend rate from $.20 to $.22 payable August 15, 1996. The Board, on November 8, 1994, reduced the quarterly dividend rate from $.355 to $.20. As a result, the annual dividend of $1.42 was reduced 44% to $.80 effective with the first quarter dividend paid in February 1995. Also, the Board authorized the purchase of up to 2 million shares of its outstanding common stock from time to time in open market transactions. Through December 31, 1996, the Company had purchased 266,100 shares at an average price of $13.69 per share. These transactions are recorded as treasury stock, at cost, in the Company's Consolidated Balance Sheet. The Company has suspended the common stock repurchase program it began in November 1994 in order to preserve capital for use in industry restructuring and other business purposes. The Company's capital structure ratios (including amounts of long-term debt due within one year) for the past three years were as follows: December 31 1996 1995 1994 ---- ---- ---- Common stock equity 53% 52% 50% Preferred stock 8 8 8 Long term debt 34 35 36 Long-term lease arrangements 5 5 6 --- --- --- 100% 100% 100% === === === On November 26, 1996, one of the Company's rating agency, Duff & Phelps Credit Rating Co. (Duff & Phelps), lowered its rating on the Company's First Mortgage Bonds and reaffirmed the Company's Preferred Stock rating. Duff & Phelps stated the downgrade reflects the Company's weak quantitative profile "when adjusted for long-term purchased power commitments (primarily from Hydro-Quebec)." However, Duff & Phelps stated that the Company's "quantitative profile is offset by a good competitive profile, an improving qualitative profile and a well-focused management team." Duff & Phelps said the Company has low cost and rate structures relative to "other northeastern utilities and . . . benefits from a moderately growing service territory and a well diversified customer mix with no significant industry concentration." Current credit ratings for the Company's securities as of February 1997 are as follows: Duff & Standard Phelps & Poor's First Mortgage Bonds BBB BBB Preferred Stock BBB- BBB- Non-Utility Catamount Energy Corporation (Catamount), a wholly owned subsidiary of the Company, implemented a credit facility in July 1996 which provides for up to $8.0 million of letters of credit and working capital loans. Currently, a $1.2 million letter of credit is outstanding to support certain of Catamount's obligations in connection with a debt reserve requirement in the Appomattox Cogeneration project and two letters of credit totaling $2.33 million to support investment commitments in Fibrowatt Thetford Ltd. SmartEnergy, also a wholly owned subsidiary of the Company, currently maintains $.5 million revolving line of credit with a bank to provide working capital and financing assistance for investment purposes. There are no outstanding borrowings under this facility. Financial obligations of the non-utility wholly owned subsidiaries are non-recourse to the Company. C&LM Programs The primary purpose of these programs is to offset the need for long-term power supply and delivery resources that are more expensive to purchase or develop than customer-efficiency programs. Total C&LM expenditures in 1995 and 1996 were $4.8 million and $3.5 million, respectively, and based on an agreement between the Company and the DPS, total 1997 C&LM expenditures are not to exceed $4.5 million. This agreement is subject to PSB approval. Diversification Catamount was formed for the purpose of investing in non-regulated power plant projects. Currently, Catamount, through its wholly owned subsidiaries, has interests in six operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Hopewell, Virginia; and Williams Lake, British Columbia, Canada. In addition, Catamount has interests in a project under construction in Thetford, England, and under development in Summersville, West Virginia. Catamount after-tax earnings were $.5 million, $2.5 million and $1.2 million for 1996, 1995 and 1994, respectively. Included in results of operation for 1996 was $2.3 million of pre-tax expenses related to the Gauley River project in Summersville, West Virginia. These expenses would be reimbursed if this pending project reaches financial closing. SmartEnergy was formed for engaging in the sale of or rental of electric water heaters, energy efficient products and other related goods and services. SmartEnergy's earnings were $.3 million for 1996 and incurred losses of $.3 million and $.9 million for 1995 and 1994, respectively. The 1995 and 1994 losses resulted from write-offs of the Company's investment in Green Technologies of $.4 million and $1.3 million, respectively. Rates and Regulation The Company recognizes that adequate and timely rate relief is necessary if the Company is to maintain its financial strength, particularly since Vermont regulatory rules do not allow for changes in purchased power and fuel costs to be passed on to consumers through automatic rate adjustment clauses. The Company's practice of reviewing costs periodically will continue and rate increases will be requested when warranted. The Company filed for a 14.6% or $31.0 million general rate increase on October 17, 1995 to become effective July 1, 1996. On February 13, 1996, the Company reached an agreement with the DPS regarding this rate increase request. On April 30, 1996, the Company received a rate order from the PSB generally approving the agreement. Under the terms of the Agreement approved by the PSB, the Company increased its Vermont retail rates 5.5% effective June 1, 1996 and 2% effective January 1, 1997. In addition, the Agreement caps the Company's allowed return on common equity in its Vermont retail business for 1996 and 1997 at 11%, by requiring the Company to reduce deferred C&LM costs to the extent its Vermont retail return on common equity would otherwise exceed 11%, and prohibits the Company from seeking any increase in Vermont retail rates which would become effective before January 1, 1998, except for extraordinary circumstances. The Agreement also requires the Company to recognize in 1997, for accounting purposes, approximately $5.8 million in power cost reductions associated with a Memorandum of Understanding with Hydro-Quebec and to file for a rate reduction if the Company is successful in negotiating any further modifications to the Contract with Hydro-Quebec that result in a reduction in the cost of power from Hydro-Quebec between February 12, 1996 and December 31, 1997. Pursuant to the common equity cap of 11%, the Company recognized in 1996 approximately $147,000 C&LM costs that would have otherwise been deferred. In its April 30, 1996 Order, the PSB modified the February 13, 1996 Agreement reached with the DPS by removing only one of the two penalties imposed in the PSB's October 31, 1994 Order. Although the PSB's April 30, 1996 Order supports the Agreement's removal of the penalty associated with the Company's efforts to acquire cost-effective energy efficiency resources, it only suspends the penalty for the alleged mismanagement of power supply options through the later of January 1, 1998 or the next investigation into the Company's rates. After this period, the rate consequences of the penalty, a .75% reduction in the Company's authorized Vermont retail return on common equity, will be reimposed unless the Company demonstrates in future proceedings that it has adequately met the standards for removal as established by the PSB in its Orders issued October 31, 1994 and April 30, 1996. During proceedings related to the April 30, 1996 Order, certain intervening parties petitioned the PSB for a management audit of the Company. In an Order dated April 10, 1996, the PSB severed the management audit issue from the rate proceeding. The PSB held a status conference on May 6, 1996 to address whether there should be such an audit as well as other related issues. Hearings for the management audit issue were held on July 16, 1996 and August 29, 1996. No decision has been issued by the PSB. On July 23, 1996, Connecticut Valley filed with the NHPUC for an 8.8% or approximately $1.6 million base rate increase to become effective September 22, 1996. The increase is to recover increased operating costs and costs of improvements to the electric system. As part of the permanent rate increase, Connecticut Valley also requested a temporary rate increase of 5.4% or approximately $.9 million. The NHPUC has granted Connecticut Valley a temporary rate increase of 5.4% effective with bills rendered October 1, 1996. On January 21, 1997, Connecticut Valley and the NHPUC Staff reached a settlement in principle regarding the permanent rate increase. The settlement, subject to NHPUC approval, provides for a 6.4% permanent rate increase and sets Connecticut Valley's allowed return on common equity at 10.2%. For the purpose of collecting recoupment revenues for the period October 1, 1996 and March 30, 1997, and to recoup rate case expenses, a temporary billing surcharge of approximately 2.2% of total bill would be effective during the period April 1 through November 30, 1997, when off-peak rates are in effect. This settlement was approved by the NHPUC in March 1997. Inflation The annual rate of inflation, as measured by the Consumer Price Index, was 3.3% for 1996, 2.5% for 1995 and 2.7% for 1994. The Company's revenues, however, are based on rate regulation that generally recognizes only historical costs. Although the rate of inflation has eased in recent years, it continues to have an impact on most aspects of the business. New Accounting Pronouncements Effective January 1, 1996, the Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" and decided not to adopt the accounting option of SFAS No. 123, "Accounting for Stock-Based Compensation." In June 1996, the FASB issued SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities," effective for transfers and servicing of financial assets and extinguishment of liabilities occurring after December 31, 1996. Earlier or retroactive application is not permitted. Subsequently, in December 1996, the FASB issued SFAS No. 127, "Deferral of the Effective Date of Certain Provisions of FASB No. 125." SFAS No. 127 defers for one year the effective date of certain provisions of SFAS No. 125. Refer to Note 14 to the Consolidated Financial Statements for additional information regarding these pronouncements. Forward Looking Statements Statements in this report relating to future financial conditions are forward looking statements. Such forward-looking statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors, which may cause the actual results, performances or achievements to differ materially from the future forward-looking statements. Such factors include general economic and business conditions, changes in industry regulation, weather and other factors which are described in further detail in the Company's filings with the Securities and Exchange Commission. Item 8. Financial Statements and Supplementary Data. Index to Financial Statements and Supplementary Data Page No. -------- Report of Independent Public Accountants 37 Financial Statements: Consolidated Statement of Income for each of the three years ended December 31, 1996 38 Consolidated Statement of Cash Flows for each of the three years ended December 31, 1996 39 Consolidated Balance Sheet at December 31, 1996 and 1995 40 Consolidated Statement of Capitalization at December 31, 1996 and 1995 41 Consolidated Statement of Changes in Common Stock Equity for each of the three years ended December 31, 1996 42 Notes to Consolidated Financial Statements 43 Report of Independent Public Accountants To the Board of Directors of Central Vermont Public Service Corporation: We have audited the accompanying consolidated balance sheet and statement of capitalization of Central Vermont Public Service Corporation and its wholly owned subsidiaries as of December 31, 1996 and 1995, and the related consolidated statements of income, changes in common stock 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 Central Vermont Public Service Corporation and its wholly owned subsidiaries as of December 31, 1996 and 1995 and the results of their operations and cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Boston, Massachusetts February 3, 1997
CONSOLIDATED STATEMENT OF INCOME (Dollars in thousands, except per share amounts) Year Ended December 31 1996 1995 1994 Operating Revenues $290,801 $288,277 $277,158 Operating Expenses Operation Purchased power 154,422 149,665 143,162 Production and transmission 20,941 20,883 21,122 Other operation 38,098 42,116 40,691 Maintenance 14,918 12,874 12,245 Depreciation 17,960 17,297 16,478 Other taxes, principally property taxes 10,971 10,543 10,423 Taxes on income 10,216 10,662 11,934 -------- -------- -------- Total operating expenses 267,526 264,040 256,055 -------- -------- -------- Operating Income 23,275 24,237 21,103 -------- -------- -------- Other Income and Deductions Equity in earnings of affiliates 3,302 3,292 3,098 Allowance for equity funds during construction 347 243 232 Other income (expenses), net 2,447 2,493 (27) Benefit (provision) for income taxes (4) (246) 525 -------- -------- -------- Total other income and deductions, net 6,092 5,782 3,828 -------- -------- -------- Total Operating and Other Income 29,367 30,019 24,931 -------- -------- -------- Interest Expense Interest on long-term debt 9,473 9,544 9,611 Other interest 615 798 657 Allowance for borrowed funds during construction (163) (174) (137) -------- -------- -------- Total interest expense, net 9,925 10,168 10,131 -------- -------- -------- Net Income 19,442 19,851 14,800 Preferred Stock Dividends Requirements 2,028 2,028 2,138 -------- -------- -------- Earnings Available For Common Stock $ 17,414 $ 17,823 $ 12,662 ======== ======== ======== Average Shares of Common Stock Outstanding 11,543,998 11,648,981 11,716,926 Earnings Per Share of Common Stock $1.51 $1.53 $1.08 Dividends Paid Per Share of Common Stock $ .84 $ .80 $1.42 The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS (Dollars in thousands) Year Ended December 31 1996 1995 1994 Cash Flows Provided (Used) By Operating Activities Net income $ 19,442 $ 19,851 $ 14,800 Adjustments to reconcile net income to net cash provided by operating activities Depreciation 17,960 17,297 16,478 Write-down investment - 424 1,332 Write-off corporate headquarters costs - - 2,857 Deferred income taxes and investment tax credits 464 2,707 3,522 Allowance for equity funds during construction (347) (243) (232) Net deferral and amortization of nuclear replacement energy and maintenance costs (1,773) (3,299) 5,353 Amortization of conservation & load management costs 5,651 3,362 1,128 Amortization of restructuring costs 327 3,937 632 Gain on sale of investment - (1,517) - Gain on sale of property (700) - - Increase in accounts receivable (1,076) (1,280) (1,598) Increase (decrease) in accounts payable 1,185 1,803 (1,298) Increase (decrease) in accrued income taxes 1,055 (2,500) 3,209 Change in other working capital items 7,890 (1,576) 1,916 Other, net (7,390) 2,745 1,327 -------- -------- -------- Net cash provided by operating activities 42,688 41,711 49,426 -------- -------- -------- Investing Activities Construction and plant expenditures (18,952) (21,337) (22,621) Deferred conservation and load management expenditures (1,589) (3,899) (6,159) Investments in affiliates (91) 249 150 Proceeds from sale of investment - 6,400 - Proceeds from sale of property 1,050 - - Special deposit (5,246) (2,686) 2,950 Non-utility investments (2,900) (226) (2,344) Other investments, net (293) (316) (423) -------- -------- -------- Net cash used for investing activities (28,021) (21,815) (28,447) -------- -------- -------- Financing Activities Issuance of long-term debt 1,250 - 2,500 Sale of common stock - - 3,988 Repurchase of common stock (1,042) (1,892) (735) Short-term debt, net (7,740) 1,994 10,155 Retirement of preferred stock - - (7,070) Retirement of long-term debt (1,018) (4,245) (5,382) Common and preferred dividends paid (11,728) (11,350) (18,845) Other 14 - (16) -------- -------- -------- Net cash used for financing activities (20,264) (15,493) (15,405) -------- -------- -------- Net Increase (Decrease) In Cash and Cash Equivalents (5,597) 4,403 5,574 Cash and Cash Equivalents at Beginning of Year 11,962 7,559 1,985 -------- -------- -------- Cash and Cash Equivalents at End of Year $ 6,365 $ 11,962 $ 7,559 ======== ======== ======== Supplemental Cash Flow Information Cash paid during the year for: Interest (net of amounts capitalized) $ 9,920 $ 9,927 $ 9,673 Income taxes (net of refunds) $ 8,504 $ 7,721 $ 4,687 Non-cash Investing and Financing Activities Regulatory assets (Notes 2 and 11) Long-term lease arrangements (Note 13) The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEET (Dollars in thousands) December 31 1996 1995 Assets Utility Plant, at original cost $461,231 $453,784 Less accumulated depreciation 146,539 136,057 -------- -------- 314,692 317,727 Construction work in progress 9,302 8,108 Nuclear fuel, net 947 1,167 -------- -------- Net utility plant 324,941 327,002 -------- -------- Investments and Other Assets Investments in affiliates, at equity 26,630 26,464 Non-utility investments 27,823 22,622 Non-utility property, less accumulated depreciation 4,498 2,896 -------- -------- Total investments and other assets 58,951 51,982 -------- -------- Current Assets Cash and cash equivalents 6,365 11,962 Special deposits 5,633 3,868 Accounts receivable 21,878 21,374 Unbilled revenues 11,673 11,177 Materials and supplies, at average cost 3,690 4,023 Prepayments 2,423 2,758 Other current assets 3,840 4,564 -------- -------- Total current assets 55,502 59,726 ======== ======== Regulatory Assets and Other Deferred Charges 63,574 50,503 -------- -------- Total Assets $502,968 $489,213 ======== ======== Capitalization And Liabilities Capitalization Common stock equity $186,469 $179,760 Preferred and preference stock 8,054 8,054 Preferred stock with sinking fund requirements 20,000 20,000 Long-term debt 117,374 119,142 Long-term lease arrangements 18,304 19,385 -------- -------- Total capitalization 350,201 346,341 -------- -------- Current Liabilities Short-term debt 5,750 13,490 Current portion of long-term debt 3,015 1,015 Accounts payable 4,432 4,726 Accounts payable - affiliates 12,109 10,559 Accrued income taxes 2,552 1,497 Dividends declared 507 507 Other current liabilities 24,184 25,252 -------- -------- Total current liabilities 52,549 57,046 -------- -------- Deferred Credits Deferred income taxes 57,463 57,191 Deferred investment tax credits 7,612 8,003 Other deferred credits 35,143 20,632 -------- -------- Total deferred credits 100,218 85,826 -------- -------- Commitments and Contingencies Total Capitalization and Liabilities $502,968 $489,213 ======== ======== The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CAPITALIZATION (Dollars in thousands) December 31 1996 1995 Common Stock Equity Common stock, $6 par value, authorized 19,000,000 shares; outstanding 11,785,848 shares $ 70,715 $ 70,715 Other paid-in capital 45,273 45,251 Treasury stock (266,100 shares and 195,100 shares, respectively, at cost) (3,656) (2,628) Retained earnings 74,137 66,422 -------- -------- Total common stock equity 186,469 179,760 -------- -------- Cumulative Preferred and Preference Stock Preferred stock, $100 par value, authorized 500,000 shares Outstanding: Non-redeemable 4.15 % Series; 37,856 shares 3,786 3,786 4.65 % Series; 10,000 shares 1,000 1,000 4.75 % Series; 17,682 shares 1,768 1,768 5.375% Series; 15,000 shares 1,500 1,500 Redeemable 8.30 % Series; 200,000 shares 20,000 20,000 Preferred stock, $25 par value, authorized 1,000,000 shares Outstanding - none - - Preference stock, $1 par value, authorized 1,000,000 shares Outstanding - none - - -------- -------- Total cumulative preferred and preference stock 28,054 28,054 -------- -------- Long-Term Debt First Mortgage Bonds 9.20 % Series EE, due 1998 7,500 7,500 9.20 % Series FF, due 2000 7,500 7,500 9.26 % Series GG, due 2002 3,000 3,000 9.97 % Series HH, due 2003 24,000 25,000 8.91 % Series JJ, due 2031 15,000 15,000 5.30 % Series KK, due 1998 10,000 10,000 5.54 % Series LL, due 2000 5,000 5,000 6.01 % Series MM, due 2003 7,500 7,500 6.27 % Series NN, due 2008 3,000 3,000 6.90 % Series OO, due 2023 17,500 17,500 Vermont Industrial Development Authority Bonds Variable, due 2013 (3.70% at December 31, 1996) 5,800 5,800 New Hampshire Industrial Development Authority Bonds 6.40%, due 2009 5,500 5,500 Connecticut Development Authority Bonds Variable, due 2015 (3.40% at December 31, 1996) 5,000 5,000 Other, various 4,089 2,857 -------- -------- 120,389 120,157 Less current portion 3,015 1,015 -------- -------- Total long-term debt 117,374 119,142 -------- -------- Long-Term Lease Arrangements 18,304 19,385 -------- -------- Total Capitalization $350,201 $346,341 ======== ======== The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY (Dollars in thousands) Other Common Stock Paid-in Treasury Retained Shares Amount Capital Stock Earnings Total Balance, December 31, 1993 11,562,219 $69,373 $42,584 $ - $ 61,879 $173,836 Sale of common stock 223,629 1,342 2,646 3,988 Treasury stock at cost (56,400) (735) (735) Net income 14,800 14,800 Cash dividends on capital stock: Common stock - $1.42 per share (16,620) (16,620) Common stock - $.20 per share (2,346) (2,346) Cumulative preferred stock: Non-redeemable (408) (408) Redeemable (1,660) (1,660) Premium (70) (70) Common stock issuance expenses (16) (16) Amortization of preferred stock issuance expenses 15 15 ---------- ------- ------- ------- -------- -------- Balance, December 31, 1994 11,729,448 70,715 45,229 (735) 55,575 170,784 Treasury stock at cost (138,700) (1,893) (1,893) Net income 19,851 19,851 Cash dividends on capital stock: Common stock - $.80 per share (6,976) (6,976) Cumulative preferred stock: Non-redeemable (368) (368) Redeemable (1,660) (1,660) Amortization of preferred stock issuance expenses 22 22 ---------- ------- ------- ------- -------- -------- Balance, December 31, 1995 11,590,748 70,715 45,251 (2,628) 66,422 179,760 Treasury stock at cost (71,000) (1,028) (1,028) Net income 19,442 19,442 Cash dividends on capital stock: Common stock - $.40 per share (4,630) (4,630) Common stock - $.44 per share (5,069) (5,069) Cumulative preferred stock: Non-redeemable (368) (368) Redeemable (1,660) (1,660) Amortization of preferred stock issuance expenses 22 22 ---------- ------- ------- ------- -------- -------- Balance, December 31, 1996 11,519,748 $70,715 $45,273 $(3,656) $ 74,137 $186,469 ---------- ------- ------- ------- -------- -------- The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1 Summary of significant accounting policies Consolidation The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. Regulation The Company is subject to regulation by the Vermont Public Service Board (PSB), the Federal Energy Regulatory Commission (FERC) and, to a lesser extent, the public utilities commissions in other New England states where the Company does business, with respect to rates charged for service, accounting and other matters pertaining to regulated operations. As such, the Company currently prepares its financial statements in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," and records various regulatory assets and liabilities. In order for a company to report under SFAS No. 71, the company's rates must be designed to recover its costs of providing service, and the company must be able to collect those rates from customers. If rate recovery of these costs becomes unlikely or uncertain, whether due to competition or regulatory action, these accounting standards may no longer apply to the company's regulated operations. Management believes that the Company currently meets the criteria for continued application of SFAS No. 71, but will continue to evaluate significant changes in the regulatory and competitive environment to assess the Company's overall consistency with the criteria of SFAS No. 71. In the event the Company determines that it no longer meets the criteria for applying SFAS No. 71, the accounting impact would be an extraordinary non-cash charge to operations of an amount that could be material. Unregulated Business The Company's two wholly owned non-regulated subsidiaries, Catamount Energy Corporation (Catamount) and SmartEnergy Services, Inc., results of operations are included in other income (expenses), net in the Other Income and Deductions section of the Consolidated Statement of Income. Catamount's policy is to expense all screening, feasibility and development expenditures incurred prior to obtaining financing commitments. Reimbursement of these costs is recorded as development revenues. Revenues Estimated unbilled revenues are recorded at the end of accounting periods. Unbilled revenues of approximately $18.5 million, $18.7 million and $18.8 million for 1994, 1995 and 1996, respectively, are included in revenues on the Consolidated Statement of Income. Maintenance Maintenance and repairs, including replacements not qualifying as retirement units of property, are charged to maintenance expense. Replacements of retirement units are charged to utility plant. The original cost of units retired plus the cost of removal, less salvage, is charged to the accumulated provision for depreciation. Depreciation The Company uses the straight-line remaining life method of depreciation. Total depreciation expense was approximately 3.6% of the cost of depreciable utility plant for each of the years 1994 through 1996. Income Taxes The Company records income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes," which requires an asset and liability approach to determine income tax liabilities. The standard recognizes tax assets and liabilities for the cumulative effect of all temporary differences between financial statement carrying amounts and the tax basis of assets and liabilities, see Note 11. Investment tax credits associated with utility plant are deferred and amortized ratably to income over the lives of the related properties. Investment tax credits associated with non-utility plant are recognized as income in the year realized. Allowance for Funds During Construction Allowance for funds used during construction (AFDC) is the cost, during the period of construction, of debt and equity funds used to finance construction projects. The Company capitalizes AFDC as a part of the cost of major utility plant projects to the extent that costs applicable to such construction work in progress have not been included in rate base in connection with rate-making proceedings. AFDC equity represents a current non-cash credit to earnings which is recovered over the life of the property. The AFDC rates used by the Company were 8.05%, 8.41%, and 9.24% for the years 1994 through 1996, respectively. Regulatory Assets and Other Deferred Charges Certain costs are deferred and amortized in accordance with authorized or expected rate-making treatment. The major components of these regulatory assets and other deferred charges are $20.1 million for Conservation and Load Management (C&LM), $8.4 million for SFAS No. 109, $6.1 million and $15.3 million for Yankee Atomic Electric Company (Yankee Atomic) and Connecticut Yankee Atomic Power Company (Connecticut Yankee) dismantling costs, respectively and $6.2 million of energy and maintenance deferrals. During regular nuclear refueling outages, the increased costs attributable to replacement energy purchased from NEPOOL and maintenance costs are deferred and amortized ratably to expense until the next regularly scheduled refueling shutdown. The Company earns a return on the unamortized C&LM and replacement energy and maintenance costs. The net regulatory asset related to the adoption of SFAS No. 109 is recovered through tax expense in the Company's cost of service generally over the remaining lives of the related property. Recovery for the unamortized dismantling costs for Yankee Atomic and Connecticut Yankee is provided without a return on investment through mid-2000 and 2007, respectively. See Note 2 to the Consolidated Financial Statements for discussion of the costs associated with the discontinued operations of the Yankee Atomic and Connecticut Yankee nuclear power plants. In addition, the Company is not earning a return on approximately $3.5 million of other unamortized deferred costs which are being recovered over periods ranging from two to 10 years. Purchased Power The Company records the annual cost of power obtained under long-term contracts as operating expenses. Since these contracts, as more fully described in Note 13, do not convey to the Company the right to use property, plant, or equipment, they are considered executory in nature. This accounting treatment is in contrast to the Company's commitment with respect to the Hydro Quebec Phase I and II transmission facilities which are considered capital leases. As such, the Company has recorded a liability for its commitment under the Phase I and II arrangements and recognized an asset for the right to use these facilities. Use of Estimates The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities and revenues and expenses. Actual results could differ from those estimates. Statement of Cash Flows The Company considers all highly liquid investments with a maturity of three months or less when acquired to be cash equivalents. Reclassifications Certain reclassifications have been made to prior year Consolidated Financial Statements to conform with the 1996 presentation. Note 2 Investments in affiliates The Company uses the equity method to account for its investments in the following companies (dollars in thousands): December 31 Ownership 1996 1995 Nuclear generating companies: Vermont Yankee Nuclear Power Corporation 31.3% $17,017 $16,740 Connecticut Yankee Atomic Power Company 2.0% 2,123 2,021 Maine Yankee Atomic Power Company 2.0% 1,420 1,412 Yankee Atomic Electric Company 3.5% 808 820 ------- ------- 21,368 20,993 Vermont Electric Power Company, Inc.: Common stock 56.8% 3,508 3,496 Preferred stock 1,754 1,975 ------- ------- $26,630 $26,464 ======= ======= Each sponsor of the nuclear generating companies is obligated to pay an amount equal to its entitlement percentage of fuel, operating expenses (including decommissioning expenses) and cost of capital and is entitled to a similar share of the power output of the plants. The Company's entitlement percentages are identical to the ownership percentages except that Vermont Yankee's entitlement percentage is 35%. The Company is obligated to contribute its entitlement percentage of the capital requirements of Vermont Yankee and Maine Yankee and has a similar, but limited, obligation to Connecticut Yankee. The Company is responsible for paying its entitlement percentage of decommissioning costs for Vermont Yankee, Connecticut Yankee, Maine Yankee and Yankee Atomic as follows (dollars in millions): CVPS's Total Share of Date of Estimated CVPS's Funded Study Obligation Obligation Obligation ------- ---------- ---------- ---------- Nuclear generating companies: Vermont Yankee 1993 $312.7 $109.4 $53.3 Maine Yankee 1993 $316.6 $6.3 $3.3 Connecticut Yankee 1996 $426.7 $8.5 $4.1 Yankee Atomic 1994 $370 $13.0 $4.6 Maine Yankee The Company owns 2% of the common stock of Maine Yankee and is entitled to approximately 2% of the power output of the 880-megawatt nuclear generating plant located in Wiscasset, Maine. In response to concerns about Maine Yankee's analysis and the NRC's review of certain computer codes used in calculating the safety of the Plant in the event of some types of accidents, in mid-July 1996 an Independent Safety Assessment Team (ISAT), commissioned by the NRC, began a four-week, on-site comprehensive review of the Plant's performance. The ISAT performed a detailed review of the licensing basis and operational safety performance of the Plant and was responsible for analyzing whether the Plant has been operating in compliance with its operating license. On July 20, 1996, the Plant was shut down as a result of a potential problem discovered by Maine Yankee personnel related to the containment cooling system. The Plant came on line on September 2, 1996 and attained its currently authorized 90% level on September 3, 1996. The Company's share of the incremental operating and maintenance costs associated with the outage was approximately $130,000 and the Company's incremental replacement power costs were about $230,000 through the date the Plant returned to service. On October 7, 1996, the NRC issued its ISAT report concluding that Maine Yankee was in general conformance with its licensing basis although significant deficiencies noted in the report resulted from 1) economic pressure to be a low cost provider had limited available resources to address corrective actions and some improvements and 2) a questioning culture was lacking, resulting in a failure to identify or promptly correct significant problems in areas perceived by Maine Yankee to be of low safety significance. However, the report concluded that despite uncorrected and previously undiscovered design problems specified in the report, the design basis and compensatory measures adequately supported operation of the Plant at a 90% power level. While Maine Yankee cannot predict when, or if, the Plant will be allowed to return to a 100% maximum capacity, the Plant's operating level may be limited to 90% of capacity until completion of the Plant's next planned refueling outage, which is currently scheduled for September 1997. On December 6, 1996, the Maine Yankee Nuclear Power Plant was again shut down after Maine Yankee's personnel discovered two cables in the reactor protective system were not properly separated as required by the NRC's design criteria. In late December 1996, Maine Yankee's management decided to place the Plant in the cold shutdown configuration and further decided to open the reactor vessel and attempt to locate the leaking fuel assembly that has been evident for the past several months. The Plant is expected to remain shut down until approximately March 1, 1997. The NRC has notified Maine Yankee that returning the Plant to service will require NRC approval and on January 30, 1997, placed the Plant on its "watch list" as a category 2 facility requiring increased NRC attention until the licensee demonstrates a period of improved performance. Maine Yankee cannot predict, at this time, when the Plant will be allowed to return to service. In 1996, the Company incurred incremental replacement power costs of approximately $450,000 while the Plant was off-line and expects such costs to be approximately $210,000 per month until the Plant returns to service. The Company's share of theincremental operating and maintenance costs associated with this outage are not expected to be material. During the refueling and maintenance shutdown that commenced in early February 1995, Maine Yankee detected an increased rate of degradation of the Plant's steam generator tubes well above its expectations and decided to repair the tubes in the plant's three steam generators by sleeving all 17,000 steam generator tubes. The sleeving process was completed in December 1995 at a total cost of approximately $28 million. The Company's share of the cost to repair the steam generator tubes was about $.6 million. The Company's additional costs for replacement power while Maine Yankee was not operating was $1.2 million. These costs were included in the Company's 1995 results of operations. Connecticut Yankee On December 4, 1996, the Board of Directors of Connecticut Yankee unanimously voted to retire the Connecticut Yankee Plant from commercial operation and decommission the Plant. The decision to prematurely retire the Plant 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 the Plant's operating license. Connecticut Yankee has undertaken a number of regulatory filings intended to implement the decommissioning of the Plant. The Plant has been out of service for safety related reasons since July 22, 1996. The Company relied on Connecticut Yankee for less than 2.0% of its system capacity. Currently, purchased power costs billed to the Company by Connecticut Yankee, including a provision for ultimate decommissioning of the unit, are being collected from the Company's customers via existing retail and wholesale rate tariffs. Connecticut Yankee has estimated that as of December 31, 1996, the sum of future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee to be approximately $762.8 million, of which the Company's total share is approximately $15.3 million. This amount is subject to ongoing review and revision and is reflected in the accompanying balance sheet both as a regulatory asset and deferred power contract obligation (current and non-current). Yankee Atomic In 1992, the Board of Directors of Yankee Atomic decided to permanently discontinue operation of their plant, and to decommission the facility. The Company relied on Yankee Atomic for less than 1.5% of its system capacity. Presently, costs billed to the Company by Yankee Atomic, which include a provision for ultimate decommissioning of the unit, are being collected from the Company's customers via existing retail rate tariffs. The Company's share of remaining costs with respect to Yankee Atomic's decision to discontinue operation is approximately $6.1 million. This amount is reflected in the accompanying balance sheet both as a regulatory asset and deferred power contract obligation (current and non-current). The Company believes that based on the current regulatory process, its proportionate share of Connecticut Yankee and Yankee Atomic decommissioning costs will be recovered through the regulatory process and, therefore, the ultimate resolution of the premature retirement of the two plants has not and will not have a material adverse effect on the Company's earnings or financial condition. Although the estimated costs of decommissioning are subject to change due to changing technologies and regulations, the Company expects that the nuclear generating companies' liability for decommissioning, including any future changes in the liability, will be recovered in their rates over their operating or license lives. The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. Beyond that a licensee maintains an indemnity agreement with the Nuclear Regulatory Commission, but subject to Congressional approval. The first $200 million of liability coverage is the maximum provided by private insurance. The Secondary Financial Protection Program is a retrospective insurance plan providing additional coverage up to $8.7 billion per incident by assessing $79.3 million against each of the 110 reactor units that are currently subject to the Program in the United States, limited to a maximum assessment of $10 million per incident per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes. The Company's interests in the nuclear power units are such that it could become liable for an aggregate of approximately $3.9 million of such maximum assessment per incident per year. Summarized financial information for Vermont Yankee Nuclear Power Corporation is as follows (dollars in thousands): Earnings 1996 1995 1994 Operating revenues $181,715 $180,437 $162,757 Operating income $14,705 $15,006 $14,355 Net income $6,985 $6,790 $6,588 Company's equity in net income $2,193 $2,111 $2,067 December 31 Investment 1996 1995 Current assets $ 38,587 $ 52,267 Non-current assets 526,413 479,026 -------- -------- Total assets 565,000 531,293 Less: Current liabilities 31,371 25,168 Non-current liabilities 478,831 452,182 -------- -------- Net assets $ 54,798 $ 53,943 -------- -------- Company's equity in net assets $ 17,017 $ 16,740 During 1996 Vermont Yankee initiated a Design Basis Documentation project (Project) expected to be completed by the end of 1997. The objective of the Project is to make certain Vermont Yankee maintains its safety margins in connection with any plant's modifications and to incorporate all design documentation into a centralized system. It will create a set of design basis documents capturing and organizing its current design, operational and licensing bases. The Project was undertaken in anticipation of an NRC generic letter sent to substantially all nuclear licensees in the United States. This NRC letter, dated October 9, 1996, requested information to be used to verify compliance with the terms and conditions of the plant's operating license and NRC regulations. The NRC has requested a written response under oath or affirmation within 120 days of receipt of the generic letter. Vermont Yankee responded to the NRC's request within the allotted time period. The Company's 35% share of the total cost for this Project is expected to be about $3.15 million. Such costs will be deferred and amortized over the remaining license life of the plant. Included in Vermont Yankee's revenues shown above are sales to the Company of $53.6 million, $52.9 million and $53.1 million for 1994 through 1996, respectively. These amounts are reflected as purchased power net of deferrals and amortization in the accompanying Consolidated Statement of Income. Vermont Electric Power Company, Inc. (Velco) and its wholly owned subsidiary Vermont Electric Transmission Company, Inc. own and operate transmission systems in Vermont over which bulk power is delivered to all electric utilities in the state. Velco has entered into transmission agreements with the state of Vermont and the electric utilities and under these agreements bills all costs, including interest on debt and a fixed return on equity, to the state and others using the system. These contracts enable Velco to finance its facilities primarily through the sale of first mortgage bonds. Included in Velco's revenues shown below are transmission services to the Company (reflected as production and transmission in the accompanying Consolidated Statement of Income) amounting to $8.4 million, $7.9 million and $7.9 million for 1994 through 1996, respectively. Velco operates pursuant to the terms of the 1985 Four-Party Agreement (as amended) with the Company and two other major distribution companies in Vermont. Although the Company owns 56.8% of Velco's outstanding common stock, the Four-Party Agreement effectively restricts the Company's control of Velco. Therefore, Velco's financial statements have not been consolidated. The Four-Party Agreement continues in full force and effect until May 1997 and will be extended for an additional two-year term in May 1997, and every two years thereafter, unless at least ninety (90) days prior to any two-year anniversary any party shall notify the other parties in writing that it desires to terminate the agreement as of such anniversary. No such notification has been filed by the parties. The Company also owns 46.6% of Velco's outstanding preferred stock, $100 par value. Summarized financial information for Velco is as follows (dollars in thousands): Earnings 1996 1995 1994 Transmission revenues $16,298 $16,398 $16,761 Operating income $2,611 $2,767 $3,350 Net income $1,216 $1,297 $1,296 Company's equity in net income $657 $650 $638 December 31 Investment 1996 1995 Current assets $22,091 $22,121 Non-current assets 51,974 49,547 ------- ------- Total assets 74,065 71,668 Less: Current liabilities 29,672 22,045 Non-current liabilities 34,487 39,193 ------- ------- Net assets $ 9,906 $10,430 ======= ======= Company's equity in net assets $ 5,262 $ 5,471 Note 3 Non-utility investments The Company's wholly owned subsidiary, Catamount Energy Corporation (Catamount) invests through its wholly owned subsidiaries in non-regulated, energy-related projects. Certain financial information for Catamount's investments is set forth in the table that follows (dollars in thousands):
Investment Generating In Service December 31 Projects Location Capacity Fuel Date Ownership 1996 1995 Rumford Cogeneration Co. L.P. Maine 85MW Coal/Wood 1990 15.1% $10,678 $10,275 Ryegate Associates Vermont 20MW Wood 1992 33.1% 6,612 6,671 Appomattox Cogeneration L.P. Virginia 41MW Coal/Wood 1982 25.3% 4,160 4,521 Black liquor NW Energy Williams Lake L.P. British Columbia, 60MW Wood 1993 8.1% 983 1,155 Canada Rupert Cogeneration Partners, Ltd. Idaho 10MW Gas 1996 50.0% 1,631 - Glenns Ferry Cogeneration Partners, Ltd. Idaho 10MW Gas 1996 50.0% 1,297 - Fibrowatt Thetford Ltd. Thetford, England 38.5MW Biomass 1998 44.0% 2,462 - ------- ------- $27,823 $22,622 ======= =======
On July 21, 1995, Catamount sold approximately half of its limited partnership's interest in Appomattox. The sale generated capital to fund new investments in independent power projects. The sale resulted in a $1.5 million gain (pre-tax) and added approximately $.08 to earnings per common share during the third quarter of 1995. Upon closing, Catamount's ownership percentage in Appomattox was reduced to 25.25%. On October 2, 1995, Catamount purchased 50% interests in two 10MW gas-fired cogeneration projects under construction located in Rupert and Glenns Ferry, Idaho. These plants came on line in November and December 1996, respectively. Catamount has committed to invest up to $4.5 million to purchase approximately 44% of the common stock of Fibrowatt Thetford Ltd. and to make up to $5 million in loans to Fibrowatt Thetford Ltd. This partnership is constructing a 38.5 MW biomass generating station in Thetford, England. At December 31, 1996, Catamount had $.8 million in a convertible loan that will be exchanged for equity in the partnership in 1997. Catamount has funded $4.5 million in escrow in support of its equity and loan commitments to the partnership. Catamount has also funded loans of $1.7 million to the partnership. Additional commitments include an equity commitment of $.8 million and $1.5 million in loans to be funded in 1997. Catamount's earnings were $1.2 million, $2.5 million and $.5 million for the years 1994 through 1996, respectively. SmartEnergy Services, Inc. (SmartEnergy) also is a wholly owned subsidiary of the Company, whose purpose is to engage in the sale of or rental of electric water heaters, energy efficient products and other related goods and services. In 1993 and 1994 SmartEnergy purchased for $1.7 million, 424,125 shares (6.8%) of Green Technologies common stock. Green Technologies of Boulder, Colorado, manufactured GreenPlug electricity savers for several types of household appliances. During the fourth quarter of 1994, SmartEnergy wrote-down its investment in Green Technologies by approximately $1.3 million and during the third quarter of 1995 wrote-off its remaining investment of approximately $.4 million to reflect management's estimate of the permanent decline in the value of the investment. This eliminated SmartEnergy's investment in Green Technologies. On December 29, 1995, Green Technologies filed for bankruptcy under Chapter 7. SmartEnergy's earnings were $.3 million for 1996 and incurred losses of $.3 million and $.9 million for 1995 and 1994, respectively. The 1995 and 1994 losses resulted from write-offs of the Company's investment in Green Technologies of $.4 million and $1.3 million, respectively. Note 4 Common Stock On June 3, 1996 the Company's board of directors (Board) increased the quarterly dividend rate from $.20 to $.22 payable August 15, 1996. The Board had reduced, on November 8, 1994, the quarterly dividend rate from $.355 to $.20. As a result, the annual dividend of $1.42 was reduced 44% to $.80 effective with the first quarter dividend paid in February 1995. Also, on November 8, 1994, the Board authorized the purchase of up to 2 million shares of its outstanding common stock from time to time in open market transactions. Through December 31, 1996, the Company had purchased 266,100 shares at an average price of $13.69 per share. These transactions are recorded as treasury stock, at cost, in the Company's Consolidated Balance Sheet. The Company has suspended the common stock repurchase program it began in November 1994 in order to preserve capital for use in industry restructuring and other business purposes. Note 5 Redeemable preferred stock Commencing in 1998, the 8.30% Dividend Series Preferred Stock is redeemable at par through a mandatory sinking fund in the amount of $1.0 million per annum, and at its option, the Company may redeem at par an additional non-cumulative $1.0 million per annum. Note 6 Long-term debt and sinking fund requirements The Company and its subsidiaries' long-term debt contains financial and non-financial covenants. At December 31, 1996, the Company and its subsidiaries were in compliance with or had waivers on all debt covenants related to its various debt agreements. Based on issues outstanding at December 31, 1996, the aggregate amount of long-term debt maturities and sinking fund requirements are approximately $3.0 million, $20.5 million, $5.5 million, $16.5 million and $4.0 million for the years 1997 through 2001, respectively. Substantially all property and plant is subject to liens under the First Mortgage Bonds. Note 7 Financial instruments The estimated fair values of the Company's financial instruments at December 31, 1996 and 1995 are as follows (dollars in thousands): 1996 1995 Carrying Fair Carrying Fair Amount Value Amount Value Cash and cash equivalents $ 6,365 $ 6,365 $ 11,962 $ 11,962 Short-term debt $ 5,750 $ 5,750 $ 13,490 $ 13,490 Sale of accounts receivable and unbilled revenues $ 12,000 $ 12,000 $ 12,000 $ 12,000 Redeemable preferred stock $ 20,000 $ 19,976 $ 20,000 $ 25,168 Long-term debt $120,389 $117,025 $120,157 $128,939 The carrying amount for cash and cash equivalents and short-term debt approximates fair value because of the short maturity of those instruments. The carrying amount for the sale of accounts receivable and unbilled revenues approximates fair value because of the short maturity of those instruments. The fair value of the Company's redeemable preferred stock and long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same remaining maturation. Based on the current regulatory treatment, any excess or decline in the fair value relative to the carrying value of the Company's financial instruments, if they were settled at amounts approximating those above, would result in an increase or decrease in the Company's rates over a prescribed amortization period. Accordingly, any settlement would not result in a material impact on the Company's financial position or results of operations. The Company has no financial instruments that fall under the guidance of SFAS No. 119, "Disclosure about Derivative Financial Instruments and Fair Value of Financial Instruments." The Company adopted SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," as of January 1, 1994. SFAS No. 115 addresses the accounting and reporting for investments in equity securities that have readily determinable fair values and for all investments in debt securities. The adoption of SFAS No. 115 had no material impact on the Company's financial position or results of operations. Note 8 Accounts receivable At December 31, 1996 and 1995, a total of $12 million of accounts receivable and unbilled revenues were sold under an accounts receivable facility. Accounts receivable and unbilled revenues that have been sold were transferred with limited recourse. A pool of assets, varying between 3% to 5% of the accounts receivable and unbilled revenues sold, are set aside for this potential recourse liability. Accounts receivable and unbilled revenues are reflected net of sales of $4.8 million and $7.2 million, respectively, at December 31, 1996 and $4.4 million and $7.6 million, respectively, at December 31, 1995. In June 1996, the FASB issued SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," effective for transfers and servicing of financial assets and extinguishments of liabilities occurring after December 31, 1996. The Company anticipates that the adoption of SFAS No. 125 will not have a material impact on the Company's financial position or results of operations. In December 1996, the FASB issued SFAS No. 127 deferring for one year the effective date of certain provisions of SFAS No. 125. Accounts receivable are also reflected net of an allowance for uncollectible accounts of $1.1 million and $1.6 million at December 31, 1996 and 1995, respectively. Note 9 Short-term debt Utility The Company uses committed lines of credit and uncommitted loan facilities to finance its construction and C&LM programs, on a short-term basis, and for other corporate purposes. As of December 31, 1996, the Company had $22.3 million of committed lines of credit and $15.0 million of uncommitted loan facilities which are normally renewed upon expiration and require annual fees ranging from zero to .25% of an individual line. Borrowings under these short-term debt arrangements are at interest rates ranging from less than prime to the prime rate. The Company had $5.8 million and $13.5 million of outstanding short-term debt at December 31, 1996 and 1995, respectively, at average interest rates of 6.49% for 1996 and 6.59% for 1995. Non-Utility Catamount implemented a credit facility in July 1996 which provides for up to $8 million of letters of credit and working capital loans. Currently, a $1.2 million letter of credit is outstanding to support certain of Catamount's obligations in connection with a debt reserve requirement in the Appomattox Cogeneration project and two letters of credit totaling $2.3 million to support investment commitments in Fibrowatt Thetford Ltd. SmartEnergy maintains a $.5 million revolving line of credit with a bank to provide working capital and financing assistance for investment purposes. There were no outstanding borrowings under this facility at December 31, 1995 and 1996. Financial obligations of the Company's non-utility wholly owned subsidiaries are non-recourse to the Company. Note 10 Pension and postretirement benefits The Company has a non-contributory trusteed pension plan covering all employees (union and non-union). Under the terms of the pension plan, employees are generally eligible for monthly benefit payments upon reaching the age of 65 with a minimum of five years of service. The Company's funding policy is to contribute, at least, the statutory minimum to a trust. The Company is not required by its union contract to contribute to multi-employer plans. The projected unit credit actuarial cost method was used to compute net pension costs and the accumulated and projected benefit obligations. The following table sets forth the funded status of the pension plan and amounts recognized in the Company's Balance Sheet and Statement of Income (dollars in thousands): December 31 1996 1995 1994 Funded status of the plan Vested benefit obligation $45,763 $47,351 $35,869 Non-vested benefit obligation 218 276 312 ------- ------- ------- Accumulated benefit obligation $45,981 $47,627 $36,181 ------- ------- ------- Projected benefit obligation $58,503 $60,554 $46,669 Market value of plan assets (primarily equity and fixed income securities) 61,932 55,443 44,115 ------- ------- ------- Projected benefit obligation more (less) than market value of plan assets (3,429) 5,111 2,554 Unrecognized net transition assets 1,286 1,447 1,608 Unrecognized prior service costs (2,779) (2,978) (3,178) Unrecognized net gain 10,099 2,270 5,963 ------- ------- ------- Net pension liability 5,177 5,850 6,947 Less regulatory asset for restructuring costs 245 346 1,974 ------- ------- ------- Effective accrued pension costs $ 4,932 $ 5,504 $ 4,973 ======= ======= ======= Net pension costs include the following components Service cost $ 2,024 $ 1,498 $ 2,065 Interest cost 4,221 4,027 3,694 Actual return on plan assets (6,461) (11,230) 515 Net amortization and deferral 2,215 7,393 (4,095) ------- ------- ------- Pension costs 1,999 1,688 2,179 Amortization of regulatory asset 101 1,628 261 ------- ------- ------- Effective pension costs 2,100 3,316 2,440 Less amount allocated to other accounts 411 337 318 ------- ------- ------- Net pension costs expensed $ 1,689 $ 2,979 $ 2,122 ======= ======= ======= Assumptions used in calculating pension cost were as follows: December 31 1996 1995 1994 Weighted average discount rates 7.50% 7.00% 8.50% Expected long-term return on assets 9.50% 9.50% 9.50% Rate of increase in future compensation levels 4.50% 4.50% 5.00% The Company sponsors a defined benefit postretirement medical plan that covers all employees who retire with ten years or more of service after age 45. The Company adopted, on a prospective basis, SFAS No. 106, "Employer's Accounting for Postretirement Benefits Other Than Pensions" (OPEB) which requires accrual of the expected costs of such benefits during the employees' years of service. In 1994, the Company adopted a policy to fund its OPEB obligation through a Voluntary Employees' Benefit Association and 401(h) Subaccount in its Pension Plan. The following table sets forth the plan's funded status and amounts recognized in the Company's Balance Sheet and the amount of expense charged to the Company's Statement of Income in accordance with SFAS No. 106 (dollars in thousands): December 31 1996 1995 1994 Accumulated postretirement benefit obligation Retirees $ 7,593 $ 8,207 $ 8,265 Fully eligible active plan participants 682 600 521 Other active plan participants 923 1,033 806 Plan assets at fair value (2,085) (1,663) (744) ------- ------- ------- Accumulated postretirement benefit obligation in excess of plan assets 7,113 8,177 8,848 Unrecognized transition obligation (4,876) (5,180) (5,485) Unrecognized net gain (loss) 229 (428) (337) ------- ------- ------- Accrued postretirement benefit cost 2,466 2,569 3,026 Less regulatory asset for restructuring costs 249 352 2,008 ------- ------- ------- Effective accrued postretirement benefit costs $ 2,217 $ 2,217 $ 1,018 ======= ======= ======= Net postretirement benefit cost includes the following components Service cost $ 208 $ 153 $ 194 Interest cost 656 755 682 Actual return on plan assets (82) (49) 1 Deferral of asset loss during the year (30) (14) (1) Amortization of transition obligation over a twenty-year period 305 305 305 ------- ------- ------- Postretirement benefit cost 1,057 1,150 1,181 Amortization of regulatory asset 103 1,656 265 ------- ------- ------- Effective postretirement benefit cost 1,160 2,806 1,446 Less amount allocated to other accounts 217 229 172 ------- ------- ------- Net postretirement benefit cost expensed $ 943 $ 2,577 $ 1,274 ======= ======= ======= Assumptions used in the per capita costs of the accumulated postretirement benefit obligation were as follows: December 31 1996 1995 1994 Per capita percent increase in health care costs: Pre-65 7.50% 8.00% 9.50% Post-65 6.00% 6.50% 8.00% Weighted average discount rates 7.50% 7.00% 8.50% Rate of increase in future compensation levels 4.50% 4.50% 5.00% Long-term return on assets 8.50% 8.50% - Health care trend rates are assumed to decrease to 5.0% for pre-65 and 4.5% for post-65 for the year 2001 and thereafter. This decrease results from changes to the retiree medical plan limiting the cost for employees retiring after 1995 to the 1995 per participant cost. Increasing the assumed health care cost trend rates by one percentage point in each year would have resulted in an increase of approximately $609,000 in the accumulated postretirement benefit obligation as of December 31, 1996, and an increase of about $43,000 in the aggregate of the service cost and interest cost components of net periodic postretirement benefit cost for 1996. Effective January 1, 1994, the Company adopted, on a prospective basis, SFAS No. 112, "Employers' Accounting for Postemployment Benefits" which requires accrual of the expected cost of postemployment benefits provided to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement. The Company provides postemployment benefits consisting of long-term disability benefits, and prior to January 1, 1994 expensed these costs as benefits were paid. The accumulated postemployment benefit obligation at December 31, 1996 of approximately $.9 million is reflected in the accompanying balance sheet as a deferred postemployment benefit obligation (current and non-current) and is offset by a corresponding regulatory asset of approximately $.7 million. The PSB in its October 31, 1994 Rate Order allowed the Company to recover the regulatory asset over a 7-1/2 year period beginning November 1, 1994 through April 30, 2002. The postemployment benefit cost charged to expense in 1994 was approximately $324,000 (pre-tax). Beginning in 1995, the Company paid premiums to insure the salary continuation portion of future long-term disability obligations. The post-employment benefit costs charged to expense in 1996 and 1995, including insurance premiums, were $177,000 and $100,000, respectively (pre-tax). In the first quarter of 1994, the Company offered and recorded an obligation related to a Voluntary Retirement Program (VRP). The VRP was accepted by 42 employees. The estimated benefit obligation for the VRP as of December 31, 1996 is about $3.0 million. This amount consists of pension benefits and postretirement medical benefits of $1.6 million and $1.4 million, respectively. Additionally, 32 employees accepted a Voluntary Severance Program (VSP) offered by the Company. The Company also announced a layoff of 20 employees on May 9, 1994. VSP and layoff obligations of $.8 million and $.2 million, respectively, were recorded in the second quarter of 1994. The VRP, VSP and layoff combined with attrition since mid-1993, yielded a total work force reduction of approximately 14%. In January 1996, the PSB issued an Accounting Order authorizing the Company to effectively cap its Vermont retail after-tax return on equity at 10.75% and reduce, in 1995, deferred restructuring costs through operating expense recognition of approximately $2.9 million. On an after tax basis, these costs represented a reduction of earnings of approximately $1.7 million or $.15 per common share. The reduction of these additional restructuring costs will reduce future annual amortization expense by approximately $.8 million through May 1999. These restructuring costs were deferred pursuant to a PSB Accounting Order dated March 11, 1994. The unamortized balance of these costs was approximately $.6 million at December 31, 1996, which will be amortized over a 29-month period beginning January 1, 1997. Note 11 Income taxes The components of Federal and state income tax expense are as follows (dollars in thousands): Year Ended December 31 1996 1995 1994 Federal: Current $ 7,890 $ 6,703 $ 6,177 Deferred 795 2,610 3,417 Investment tax credits, net (391) (391) (391) ------- ------- ------- 8,294 8,922 9,203 ------- ------- ------- State: Current 1,866 1,498 1,710 Deferred 60 488 496 ------- ------- ------- 1,926 1,986 2,206 ------- ------- ------- Total Federal and state income taxes $10,220 $10,908 $11,409 ======= ======= ======= Federal and state income taxes charged (credited) to: Operating expenses $10,216 $10,662 $11,934 Other income 4 246 (525) ------- ------- ------- $10,220 $10,908 $11,409 ======= ======= ======= The principal items comprising the difference between the total income tax expense and the amount calculated by applying the statutory Federal income tax rate to income before tax are as follows (dollars in thousands): Year Ended December 31 1996 1995 1994 Income before income tax $29,662 $30,759 $26,209 Federal statutory rate 35% 35% 35% Federal statutory tax expense $10,382 $10,766 $ 9,173 Increases (reductions) in taxes resulting from: Insurance settlement (470) - - Disallowed regulatory tax asset - - 1,641 Dividend received deduction (909) (903) (854) Deferred taxes on plant 324 324 523 State income taxes net of Federal tax benefit 1,252 1,291 1,434 Investment credit amortization (391) (391) (391) Seabrook project 24 22 76 Book-to-return adjustments and other 8 (201) (193) ------- ------- ------- Total income tax expense provided $10,220 $10,908 $11,409 ======= ======= ======= The tax effects of temporary differences and tax carry forwards that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below (dollars in thousands): Year Ended December 31 1996 1995 1994 Deferred tax assets Alternative minimum tax credit carry forward $ - $ 203 $ 900 Non-deductible accruals and other 5,212 4,887 4,682 Deferred compensation and pension 3,562 3,546 4,651 Environmental costs accrual 2,089 2,205 2,335 ------- ------- ------- Total deferred tax assets 10,863 10,841 12,568 ------- ------- ------- Deferred tax liabilities Property, plant and equipment 46,083 45,670 41,609 Net regulatory asset 8,305 9,084 12,217 Conservation and load management expenditures 8,147 8,211 7,664 Nuclear refueling costs 2,510 1,782 473 Other 3,281 3,285 3,315 ------- ------- ------- Total deferred tax liabilities 68,326 68,032 65,278 ------- ------- ------- Net deferred tax liability $57,463 $57,191 $52,710 ======= ======= ======= As a result of the October 31, 1994 PSB Rate Order, during the fourth quarter of 1994, the Company recognized an additional $1.6 million of tax expense related primarily to a previous revenue agent review which were expected to be collected from customers through rates. A valuation allowance has not been recorded, as the Company expects all deferred income tax assets will be utilized in the future. Note 12 Retail Rates The Company filed for a 14.6% or $31.0 million general rate increase on October 17, 1995 to become effective July 1, 1996, to offset the increasing cost of providing service. On February 13, 1996 the Company reached an agreement with the DPS regarding this rate increase request. On April 30, 1996 the Company received a rate order from the PSB generally approving the agreement. Under the terms of the Agreement approved by the PSB, the Company increased its Vermont retail rates 5.5% effective June 1, 1996 and 2% effective January 1, 1997. In addition, the Agreement caps the Company's allowed return on common equity in its Vermont retail business for 1996 and 1997 at 11%, by requiring the Company to reduce deferred C&LM costs to the extent its Vermont retail return on common equity would otherwise exceed 11%, and prohibits the Company from seeking any increase in Vermont retail rates which would become effective before January 1, 1998, except for extraordinary circumstances. The Agreement also requires the Company to recognize in 1997, for accounting purposes, approximately $5.8 million in power cost reductions associated with a Memorandum of Understanding with Hydro-Quebec and to file for a rate reduction if the Company is successful in negotiating any further modifications to the Contract with Hydro-Quebec that result in a reduction in the cost of power from Hydro-Quebec between February 12, 1996 and December 31, 1997. Pursuant to the common equity cap of 11%, the Company recognized, in 1996, approximately $147,000 C&LM costs that would have otherwise been deferred. In its April 30, 1996 Order, the PSB modified the February 13, 1996 Agreement reached with the DPS by removing only one of the two penalties imposed in the PSB's October 31, 1994 Order. Although the PSB's April 30, 1996 Order supports the Agreement's removal of the penalty associated with the Company's efforts to acquire cost-effective energy efficiency resources, it only suspends the penalty for the alleged mismanagement of power supply options through the later of January 1, 1998 or the next investigation into the Company's rates. After this period, the rate consequences of the penalty, a .75% reduction in the Company's authorized Vermont retail return on common equity, will be reimposed unless the Company demonstrates in future proceedings that it has adequately met the standards for removal as established by the PSB in its Orders issued October 31, 1994 and April 30, 1996. During proceedings related to the April 30, 1996 Order, certain intervening parties petitioned the PSB for a management audit of the Company. In an Order dated April 10, 1996, the PSB severed the management audit issue from the rate proceeding. Hearings were held on July 16 and August 29, 1996 addressing issues related to management practices. No decision has been issued by the PSB. A PSB Rate Order dated October 31, 1994, subsequently amended, allowed the Company a base retail rate increase of 5.07% or approximately $10.2 million. The PSB Rate Order also lowered the allowed rate of return on the Company's common stock equity from 12% to 10%. The allowed return on equity is after deducting two concurrent .75% penalties based on the PSB's conclusions that there had been "mismanagement of power supply options" and because of "the Company's failed efforts to acquire all cost-effective energy efficiency resources." The Company disagrees with the PSB's conclusion. On July 23, 1996 the Company's wholly owned New Hampshire subsidiary, Connecticut Valley Electric Company Inc. (Connecticut Valley) filed with the New Hampshire Public Utilities Commission (NHPUC) for an 8.8% or approximately $1.6 million base rate increase to become effective September 22, 1996. The increase is to recover increased operating costs and costs of improvements to the electric system. As part of the permanent rate increase, Connecticut Valley also requested a temporary rate increase of 5.4% or approximately $.9 million. The NHPUC has granted Connecticut Valley a temporary rate increase of 5.4% effective with bills rendered October 1, 1996. On January 21, 1997, Connecticut Valley and the NHPUC Staff reached a settlement in principle regarding the permanent rate increase. The settlement, subject to NHPUC approval, provides for a 6.4% permanent rate increase and sets Connecticut Valley's allowed return on common equity at 10.2%. For the purpose of collecting recoupment revenues for the period October 1, 1996 and March 30, 1997, and to recoup rate case expenses, a temporary billing surcharge of approximately 2.2% of total bill would be effective during the period April 1 through November 30, 1997, when off-peak rates are in effect. This settlement was approved by the NHPUC in March 1997. Note 13 Commitments and contingencies The Company's power supply is acquired from a number of sources including its own generating units, jointly owned units, long-term contracts and short-term purchases from a variety of sources. The cost of power obtained from sources other than wholly and jointly owned units, including payments required to be made whether or not energy is received by the Company, is reflected as Purchased power in the Consolidated Statement of Income. Through its investments in four nuclear generating companies, the Company is entitled to receive power from those nuclear units. See Note 2 for a discussion of the Company's obligations related to its investment in nuclear generating companies. The Company is also a joint owner of the Millstone Unit #3 (Unit #3) nuclear generating plant. Through Velco, the Company purchases power from a coal-fired generating plant owned by Northeast Utilities (NU) under a thirty-year contract which expires April 30, 1998. Under this contract the Company is obligated to make capacity payments which amounted to approximately $4.3 million, $4.2 million and $4.6 million for 1994 through 1996, respectively. These capacity payments will vary over the contract period due to factors such as changes in NU's net investment, allowed rate of return and operating and maintenance costs. The Company purchases power from several small power producers who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy using hydroelectric, wood, biomass, and refuse-burning generation. Under these long-term contracts, in 1996 the Company purchased 219,584 MWH of which approximately 159,064 MWH is associated with the Vermont Electric Power Producers and 37,203 MWH with the New Hampshire/Vermont Solid Waste Plant owned by Wheelabrator Claremont Company, L.P. The Company expects to purchase approximately 199,269 MWH of small power output in each year 1997 through 2001. Based on the forecast level of production, the total commitment in the next five years to purchase power from these qualifying facilities is estimated to be $109.9 million. The Company will receive varying amounts of capacity and energy from Hydro-Quebec under the Vermont Joint Owners (VJO) contract during the 1997 to 2016 period. A contract between the State of Vermont and Hydro-Quebec terminated on September 22, 1995. Related contracts were negotiated between the Company and Hydro-Quebec which in effect alter the terms and conditions contained in the VJO contract, reducing the overall power requirements and cost of the original contract. The maximum net amount of capacity that the Company will purchase during the term of the Hydro-Quebec agreements is 143 MW. The total commitment in the next five years to purchase power under these contracts is approximately $355 million, less approximately $80 million of power sellbacks, yielding a net cost of approximately $275 million. In February 1996, the Company reached an agreement with Hydro-Quebec that will lower our 1997 cost of power by approximately $5.8 million. As part of this agreement, the Company will deliver to NEPOOL under existing firm energy contracts or joint marketing activities 54 MW of Phase II transmission capacity for a five- year period beginning July 1, 1996 through June 30, 2001. In addition, the agreement provides for continuing negotiations with Hydro-Quebec to further reduce future power cost increases. In the early phase of the VJO contract, two sellback contracts were negotiated, the first delaying the purchase of about 24 MW of capacity and associated energy, the second reducing the net purchase of Hydro-Quebec power. In 1994, the Company negotiated a third sellback arrangement whereby the Company receives an effective discount on up to 70 MW of capacity starting in November 1995 for the 1996 contract year (declining to 30 MW in the 1999 contract year). In exchange for this sellback, Hydro-Quebec has the right to reduce capacity deliveries by up to 50 MW beginning as early as 2004 until 2015, including the use of a like amount of the Company's Phase I/II facility rights and the ability to reduce the amounts of energy delivered during a five-year term beginning in 2000. Joint-ownership The Company's ownership interests in jointly owned generating and transmission facilities are set forth in the table that follows and recorded in the Company's Consolidated Balance Sheet (dollars in thousands):
Fuel In Service MW December 31 Type Ownership Date Entitlement 1996 1995 ---- --------- ---------- ----------- ---- ---- Generating plants: Wyman #4 Oil 1.78% 1978 11 $ 3,342 $ 3,340 Joseph C. McNeil Various 20.00% 1984 11 15,002 14,931 Millstone Unit #3 Nuclear 1.73% 1986 20 75,329 75,380 Highgate transmission facility 46.08% 1985 12,790 12,786 -------- -------- 106,463 106,437 Accumulated depreciation 31,755 28,824 -------- -------- $ 74,708 $ 77,613 ======= ======
The Company's share of operating expenses for these facilities is included in the corresponding operating accounts on the Consolidated Statement of Income. Each participant in these facilities must provide for its own financing. The Company is responsible for paying its ownership percentage of decom- missioning costs for Unit #3. Based on a 1995 study, the total estimated obligation at December 31, 1996 was approximately $426.7 million and the funded obligation was about $116.8 million. The Company's share for the total obligation and funded obligation was approximately $7.4 million and $1.7 million, respectively. On March 30, 1996, Unit #3 was shut down by the licensee following an engineering evaluation which determined that four safety-related valves would not be able to perform their design function during certain assumed events. For additional information in regard to NRC activities at the Millstone Nuclear Power Station see Management's Discussion and Analysis of Financial Condition and Results of Operations herein. Environmental The Company is engaged in various operations and activities which subject it to inspection and supervision by both Federal and state regulatory authorities including the United States Environmental Protection Agency (EPA). It is Company policy to comply with all environmental laws. The Company has implemented various procedures and internal controls to assess and assure compliance. If non-compliance is discovered, corrective action is taken. Based on these efforts and the oversight of those regulatory agencies having jurisdiction, the Company believes it is in compliance, in all material respects, with all pertinent environmental laws and regulations. Company operations occasionally result in unavoidable, inadvertent releases of regulated substances or materials, for example the rupture of a pole mounted transformer, or a broken hydraulic line. Whenever the Company learns of such a release, the Company responds in a timely fashion and in a manner that complies with all Federal and state requirements. Except as discussed in the following paragraphs, the Company is not aware of any instances where it has caused, permitted or suffered a release or spill on or about its properties or otherwise which will likely result in any material environmental liabilities to the Company. The Company is an amalgamation of more than 100 predecessor companies. Those companies engaged in various operations and activities prior to being merged into the Company. At least two of these companies were involved in the production of gas from coal to sell and distribute to retail customers at three different locations. These activities were discontinued by the Company in the late 1940's or early 1950's. The coal gas manufacturers, other predecessor companies, and the Company itself may have engaged in waste disposal activities which, while legal and consistent with commercially accepted practices at the time, may not meet modern standards and thus represent potential liability. The Company continues to investigate, evaluate, monitor and, where appropriate, remediate contaminated sites related to these historic activities. The Company's policy is to accrue a liability for those sites where costs for remediation, monitoring and other future activities are probable and can be reasonably estimated. For related information see Legal Proceedings below. Cleveland Avenue Property One such site is the Company's Cleveland Avenue property located in the City of Rutland, Vermont, a site where one of its predecessors operated a coal-gasification facility and later the Company sited various operations functions. Due to the presence of coal tar deposits and Polychlorinated Biphenyl (PCB) contamination and uncertainties as to potential off-site migration of those contaminants, the Company conducted studies in the late 1980's and early 1990's to determine the magnitude and extent of the contamination. The Company engaged a consultant to assist in evaluating clean-up methodologies and provide cost estimates. Those studies indicated the cost to remediate the site would be approximately $5 million. This was charged to expense in the fourth quarter of 1992. Site investigation continued over the next several years. In January of 1995, the Company was formally contacted by the EPA asking for written consent to conduct a site evaluation of the Cleveland Avenue property. That evaluation has been completed. The Company does not believe the EPA's evaluation changes its potential liability so long as the state remains satisfied that reasonable progress continues to be made in remediating the site and retains oversight of the process. In 1995, as part of that process, the Company's consultant completed its risk assessment report and submitted it to the State of Vermont for review. The State generally agreed with that assessment but expressed a number of concerns. The Company has addressed almost all of the concerns expressed by the State and continues to work with the State in a joint effort to develop a mutually acceptable solution. The Company selected a consulting/engineering firm to collect additional data and develop and implement a remediation plan for the site. That firm has begun work at the site. It will collect the additional data requested by the State and will use all the data gathered to date to formulate a comprehensive remediation plan. The additional data gathered to date has not caused the Company to alter its original estimate of the likely cost of remediating the site. PCB, Inc. In August 1995, the Company received an Information Request from the EPA pursuant to a Superfund investigation of two related sites, one in the state of Kansas and the other in the state of Missouri (the Sites). During the mid-1980's, these Sites received materials containing PCBs from hundreds of sources, including the Company. According to the EPA, more than 1,200 parties have been identified as Potential Responsible Parties (PRPs). The Company has complied with the information request and will monitor EPA activities at the Sites. In December 1996, the Company received an invitation to join a PRP steering committee. That committee has estimated the Company's pro rata share of the waste sent to the Sites to be .42%. The committee estimates that the Sites' remediation will cost between $5 million and $40 million. Based on this information, the Company does not believe that the Sites represent the potential for a material adverse effect on its financial condition or results of operations. The Company also faces potential liability arising from the alleged disposal of hazardous materials at three former municipal landfills: the Bennington Landfill, the Parker Landfill, and the Trafton-Hoisington Landfill. Bennington Landfill The Bennington Landfill is a Superfund site located in Bennington, Vermont. An investigation by the Company suggests that it is unlikely that it contributed a meaningful amount of hazardous substances, if any, to the site. In July 1994, the EPA notified the Company that it had reviewed evidence which, in its opinion, indicated that the Company may have contributed to the environmental contamination at the Bennington site but that a full determination of its potential liability for the site had not been made. EPA, at that time, designated the Company a potentially interested party (PIP). Also in July 1994, the EPA notified the PRP Group, the Company and other PIPs that it was proposing a response action at the site with an estimated total cost of approximately $9.5 million. During November 1994, the Company was notified that EPA had information indicating that the Company was a PRP with regard to the Bennington site. The EPA letter also requested that the Company participate with other PRPs in the response action described above and further made a demand against the Company and other PRPs for reimbursement of an aggregate of $.85 million in costs EPA had incurred in responding to conditions at the site. The original PRP Group reformed into a larger group, incorporating additional PRPs, including the Company, to undertake the remedial response, reimburse EPA's response expenses of $3 million it spent on its Engineering Evaluation/Cost Analysis. The Company determined its interests would be best served by participating in the larger PRP Group while at the same time exploring the possibility of a "De Minimis" settlement with the EPA, either alone or as part of a group, premised on its minimal contribution to the site. Negotiations between the PRP Group and the EPA continue. The PRP Group and EPA recently reached a tentative agreement. Under the terms of that agreement, and a related internal allocation, the Company's liability would be less than $100,000. If a final settlement is not achieved, the Company will continue to explore its settlement options, individually and as a part of a group of "De Minimis" parties. If all efforts at settlement fail, the Company will defend any contribution action brought by the other PRPs or the EPA. Parker and Trafton-Hoisington Landfills There have been no further developments involving the Company at these sites. The Company's investigations at the time it was originally contacted indicated that it contributed little if any hazardous substances to the sites. The Company has not been contacted by the EPA, the state or any of the PRPs since 1994. Therefore, the Company believes that the likelihood that these sites will cause the Company to accrue significant liability has significantly diminished. For historical information pertaining to these sites, refer to the Company's 1995 Form 10-K. At this time, the Company does not believe these landfill sites represent the potential for a material adverse effect on its financial condition or results of operations but it will continue to monitor activities at the sites. The Company is not subject to any pending or threatened litigation with respect to any other sites that have the potential for causing the Company to incur material remediation expenses, nor has the EPA or other Federal or state agency sought contribution from the Company for the study or remediation of any such sites. The Company recently filed a Federal law suit against several insurance companies. In its complaint, the Company alleges that general liability policies issued by the insurer provide coverage for all expenses incurred or to be incurred by the Company in conjunction with, among others, the Cleveland Avenue Property and the Bennington Landfill sites. Due to the uncertainties associated with the outcome of this law suit, no receivables have been recorded. Dividend restrictions The indentures relating to long-term debt and the Articles of Association contain certain restrictions on the payment of cash dividends on capital stock. Under the most restrictive of such provisions, approximately $66.3 million of retained earnings was not subject to dividend restriction at December 31, 1996. Leases and support agreements The Company participated with other electric utilities in the construction of the Phase I Hydro-Quebec transmission facilities in northeastern Vermont, which were completed at a total cost of approximately $140 million. Under a support agreement relating to the Company's participation in the facilities, the Company is obligated to pay its 4.42% share of Phase I Hydro-Quebec capital costs over a 20-year recovery period through and including 2006. The Company also participated in the construction of Phase II Hydro-Quebec transmission facilities constructed throughout New England, which were completed at a total cost of approximately $487 million. Under a similar support agreement, the Company is obligated to pay its 5.132% share of Phase II Hydro-Quebec capital costs over a 25-year recovery period through and including 2015. All costs under these support agreements are recorded as purchased transmission expense in accordance with the Company's rate-making policies. Future minimum payments will be approximately $3.0 million for each year from 1997 through 2015 and will decline thereafter. The Company's shares of the net capital cost of these facilities, totaling approximately $19.4 million, are classified in the accompanying Consolidated Balance Sheet as "Utility Plant" and "Long-term Lease Arrangements" (current and non-current). Minimum rental commitments of the Company under non-cancelable leases as of December 31, 1996, are not material. Total rental expense entering into the determination of net income, consisting principally of vehicle and equipment rentals, was approximately $3.3 million for both 1994 and 1995, and $3.2 million for 1996. Legal proceedings On December 30, 1994, the Company and its board were named as defendants in a complaint filed in the United States District Court for the District of Vermont by three shareholders. The complaint alleged, among other things, (I) that F. Ray Keyser Jr., Chairman of the Company's board, violated Section 8 of the Clayton Act, 15 U.S.C. Subchapter 19, which precludes certain interlocking directorships, (ii) that Mr. Keyser violated his fiduciary duties to the Company's stockholders by acquiring and operating a series of businesses in competition with the Company without offering those business opportunities to the Company, (iii) that the remaining individual defendants violated their fiduciary duties to the Company's stockholders by failing to analyze, or to cause management to analyze, diversification into propane and fossil fuels, and by failing to make the Company an effective competitor of alternative fuel companies, and (iv) that the Company violated the applicable provision of the Vermont General Corporation Law by failing to provide a list of the Company's stockholders. The complaint sought an unspecified amount of damages (including treble damages against Mr. Keyser), attorneys' fees and costs, a list of the Company's stockholders, and a court order to enjoin the defendants from alleged continuing violations of the law. Each of the individual defendants and the Company itself denied the allegations against them and filed a Motion to Dismiss. In an Order dated September 20, 1996, the U. S. District Court Judge dismissed all of the claims filed against the Company and its directors. On July 29, 1996, the Company filed a Declaratory Judgment action in the United States District Court for the District of Vermont. The Complaint names as defendants a number of insurance companies that issued policies to the Company dating from the mid-1940s to the late 1980s. The Company asserts that policies issued by defendants provide coverage for all defense and remediation costs associated with the Cleveland Avenue property, the Bennington Landfill site and the North Clarendon site. With the exception of the North Clarendon site where no further remediation is anticipated, see Environmental above for related disclosures. Note 14 New Accounting Pronouncements In March 1995, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective for fiscal years beginning after December 15, 1995. SFAS No. 121 establishes accounting standards for the impairment of long-lived assets and requires that regulatory assets which are no longer probable of recovery through future revenues be charged to earnings. The Company adopted SFAS No. 121 on January 1, 1996, and based on the current regulatory rate-making process, the adoption of SFAS No. 121 did not have a material impact on the Company's financial position or results of operations. In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation," effective for fiscal years beginning after December 15, 1995. SFAS No. 123 requires that financial statements include certain disclosures related to stock-based employee compensation arrangements regardless of the method used to account for them. The Company did not adopt the accounting under this pronouncement but rather elected to adopt the required audited pro forma disclosure if the impact was determined to be material. Based on the requirements of the pronouncement, the pro forma effects on earnings and earnings per common share are not material. In June 1996, the FASB issued SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," effective for transfers and servicing of financial assets and extinguishments of liabilities occurring after December 31, 1996. Earlier or retroactive application is not permitted. Subsequently, in December 1996, the FASB issued SFAS No. 127, "Deferral of the Effective Date of Certain Provisions of SFAS No. 125." This statement defers for one year the effective date of certain provisions of SFAS No. 125. The Company anticipates that the adoption of SFAS No. 125 will not have a material impact on the Company's financial position or results of operations. Note 15 Non-recurring Charge During the fourth quarter of 1994, the Company wrote-off approximately $2.9 million of costs associated with the Company's decision to discontinue its proposed new headquarters office building which reduced after tax earnings by approximately $1.7 million. Note 16 Unaudited Quarterly Financial Information The following quarterly financial information is unaudited and includes all adjustments consisting of normal recurring accruals which are, in the opinion of management, necessary for a fair statement of results of operations for such periods. Variations between quarters reflect the seasonal nature of the Company's business (dollars in thousands, except per share amounts): Quarter Ended --------------------------------------- 12 Months March June September December Ended ----- ---- --------- -------- --------- 1996 Operating revenues $84,246 $61,390 $63,833 $81,332 $290,801 Operating income $14,236 $ 1,396 $ 274 $ 7,369 $ 23,275 Net income (loss) $14,758 $ (447) $ (785) $ 5,916 $ 19,442 Earnings (loss) per share of common stock $1.23 $(.08) $(.11) $.47 $1.51 1995 Operating revenues $86,863 $62,846 $60,314 $78,254 $288,277 Operating income $14,928 $ 314 $ 1,922 $ 7,073 $ 24,237 Net income (loss) $13,796 $(1,063) $ 1,748 $ 5,370 $ 19,851 Earnings (loss) per share of common stock $1.13 $(.13) $ .11 $ .42 $1.53 Note 17 Subsequent Event (Unaudited) On February 28, 1997 the NHPUC released its Final Plan to restructure the electric utility industry in New Hampshire pursuant to legislation enacted in New Hampshire during 1996. Concurrently, supplemental utility-specific orders to establish interim stranded cost charges were issued. Each utility is required to file comprehensive plans no later than June 30, 1997 which comply with the Final Plan and the supplemental orders. However, the 1996 legislation states that utilities shall not be required to implement their compliance filings unless compliance filings representing at least seventy percent of New Hampshire retail kilowatt hour sales, on an annual basis, have been or are being implemented. In its Final Plan, the NHPUC announced a departure from cost-based ratemaking and instead adopted a market-priced approach to stranded cost recovery. In addition, the supplemental order specific to Connecticut Valley denies stranded cost recovery related to its FERC approved power contract with the Company and further ordered Connecticut Valley to terminate the contract. The net revenue loss associated with costs potentially disallowed under the power contract are preliminarily estimated by the Company to total approximately $80.0 million (pre-tax) over a twenty-eight year period on a nominal dollar basis. The Company intends to vigorously pursue the recovery of these costs and will continue to assess the likelihood of recovery. If it is determined that it is probable that FERC will not permit recovery of these costs, the Company would have to assess the likelihood and magnitude of losses incurred under both SFAS No. 5, "Accounting for Contingencies" and SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and for Long Lived Assets to be Disposed Of." Unless the Final Plan or supplemental order is stayed or modified, Connecticut Valley will no longer be able to apply SFAS No. 71, "Accounting For The Effects of Certain Types of Regulation," and the Company may have to remove from its balance sheet substantially all of its regulatory assets associated with New Hampshire regulated business as of the quarter ended March 31, 1997. The amount of the first quarter 1997 potential write-off is estimated at approximately $2.6 million on a pre-tax basis. On March 17, 1997, the NHPUC issued an Order approving a motion for rehearing and stay of its Final Plan regarding the NHPUC's market-priced approach for determining interim stranded cost charges. The Final Plan and supplemental order also contain rulings on numerous issues that may have a substantial effect on the operations of the Company. Included among these rulings is the requirement that Connecticut Valley divest within two years all of its wholesale power purchase contracts; a prohibition on the remaining distribution company and its affiliates from engaging in retail marketing or load aggregation services; and a mandate for the filing of tariffs with the FERC for the provision of unbundled retail transmission service. The supplemental order did approve the recovery through interim stranded cost charges of the projected above market power costs associated with purchases from Qualifying Facilities that were previously approved by the NHPUC. The Company intends to fully examine its legal remedies and to vigorously pursue them. The Company cannot predict whether the ultimate outcome of this matter would have a material adverse effect on the Company's financial position, results of operations, cash flows, and ability to obtain capital at competitive rates. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. PART III Item 10. Directors and Executive Officers of the Registrant. The information required by this item concerning directors of the Company is set forth in the sections entitled "Election of Directors" and "Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy Statement of the Company for the 1997 Annual Meeting of Stockholders, which are being incorporated herein by reference. The following sets forth the Executive Officers of the Company and a wholly owned subsidiary. There are no family relationships among the executive officers. Officers are normally elected annually. Executive Officers of the Registrant: Name and Age Office Officer Since - - ------------ ------ ------------- Robert H. Young, 49 President and Chief Executive Officer 1987 Robert de R. Stein, 47(a) Senior Vice President-Energy Resources and External Markets 1988 Francis J. Boyle, 51 Vice President-Finance & Administration and Principal Financial Officer 1995 Kent R. Brown, 51 Vice President-Engineering and Operations 1996 Joseph M. Kraus, 42 Vice President, Secretary and General Counsel 1987 Thomas J. Hurcomb, 59 Vice President-Marketing and Public Affairs 1975 Robert G. Kirn, 45(a) Vice President-Engineering and Operations 1991 William J. Deehan, 44 Vice President-Regulatory Affairs and Strategic Analysis 1991 Jonathan W. Booraem, 58 Treasurer 1984 James M. Pennington, 41 Controller and Principal Accounting Officer 1993 L. Douglas Barba, 49 Senior Vice President and General Manager 1992 Mr. Young joined the Company in 1987. He was elected Director, President and Chief Executive Officer in 1995. Prior to being elected to his present position, he was elected Executive Vice President and Chief Operating Officer in 1993 and Senior Vice President - Finance and Administration in 1988. Mr. Boyle joined the Company in October, 1995, as Vice President - Finance and Administration and Chief Financial Officer. From 1993 to 1995, Mr. Boyle served as Chief Financial Officer of Westmoreland Coal Company ("Westmoreland") in Philadelphia, Pennsylvania. In November, 1994, Westmoreland and several of its subsidiaries commenced Chapter 11 proceedings to confirm a so-called "prepackaged" plan of reorganization under which the court was asked to approve a sale of assets, the proceeds of which were to be used to satisfy in full certain maturing obligations of Westmoreland. In December 1994, Westmoreland's plan of reorganization was confirmed, the asset sale was consummated, the obligations in question were paid, and Westmoreland emerged from Bankruptcy. On December 23, 1996, Westmoreland and four of its subsidiaries commenced Chapter 11 proceedings. The Chapter 11 proceedings were precipitated by large liabilities Westmoreland and four of its subsidiaries have to retiree medical benefit plans for the benefit of retired mine workers. From 1985 to 1992, Mr. Boyle was Chief Financial Officer of El Paso Natural Gas Company, El Paso, Texas. Mr. Brown joined the Company in September 1996, as Vice President - Engineering and Operations. From 1992 to 1995 he served as Chairman, President and Chief Executive Officer of Kansas Gas and Electric Company ("KG&E") and Group Vice President of KG&E from 1982 to 1992. Mr. Hurcomb joined the Company in 1967. He was elected Vice President - External Affairs in 1975, and Vice President - Marketing and Public Affairs in 1993. Mr. Deehan joined the Company in 1985. Prior to being elected to his present position in 1996, he was elected Assistant Vice President - Rates and Economic Analysis in 1991. Mr. Booraem joined the Company in 1969 and was elected to his present position in 1984. Mr. Kraus joined the Company in 1981. Prior to being elected to his present position in 1996, he was elected as Corporate Secretary and Senior Corporate Counsel in 1987 and Corporate Secretary and General Counsel in 1994. Mr. Pennington joined the Company in 1989. He was named Director of Taxes and Plant Accounting in 1990. Mr. Pennington was designated Acting Controller effective July 19, 1992, and was elected Controller and named Principal Accounting Officer in 1993. Mr. Barba joined Catamount Energy Corporation, a wholly owned subsidiary of the Company, in August 1992 as Senior Vice President and General Manager. From 1990 to 1992, Mr. Barba served as Vice President, Project Finance of Cogentrix, Inc., Charlotte, N. C. (a) Robert de R. Stein and Robert G. Kirn resigned from the Company effective September 2, 1996. The term of each officer is for one year or until a successor is elected. Item 11. Executive Compensation. The information required by this item concerning executive compensation and directors' compensation is set forth in the sections entitled "Directors' Compensation," "Compensation Committee Interlocks and Insider Participation," "Report of the Compensation Committee on Executive Compensation," "Five-Year Shareholder Return Comparison Performance Graph" and "Executive Compensation and Other Transactions" in the Proxy Statement of the Company for the 1997 Annual Meeting of Stockholders, which are being incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management. The information required by this item concerning security ownership is set forth in the section entitled "Stock Ownership of Directors, Nominees and Executive Officers" in the Proxy Statement for the 1997 Annual Meeting of Stockholders, which is being incorporated herein by reference. Item 13. Certain Relationships and Related Transactions. The information required by this item is set forth in the sections entitled "Report of Indemnification and Advancement of Expenses" and "Compensation Committee Interlocks and Insider Participation." Filed Herewith at Page -------- PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a)1. The following financial statements for Central Vermont Public Service Corporation and its wholly owned subsidiaries are filed as part of this report: (See Item 8) 1.1 Consolidated Statement of Income, for each of the three years ended December 31, 1996 Consolidated Statement of Cash Flows, for each of the three years ended December 31, 1996 Consolidated Balance Sheet at December 31, 1996 and 1995 Consolidated Statement of Capitalization at December 31, 1996 and 1995 Consolidated Statement of Changes in Common Stock Equity for each of the three years ended December 31, 1996 Notes to Consolidated Financial Statements (a)2. Financial Statement Schedules: 2.1 Central Vermont Public Service Corporation and its wholly owned subsidiaries: Schedule II - Reserves for each of the three years ended December 31, 1996 Schedules not included have been omitted because they are not applicable or the required information is shown in the financial statements or notes thereto. Separate financial statements of the Registrant (which is primarily an operating company) have been omitted since they are consolidated only with those of totally held subsidiaries. Separate financial statements of subsidiary companies not consolidated have been omitted since, if considered in the aggregate, they would not constitute a significant subsidiary. Separate financial statements of 50% or less owned persons for which the investment is accounted for by the equity method by the Registrant have been omitted since, if considered in the aggregate, they would not constitute a significant investment. (a)3. Exhibits (* denotes filed herewith) Each document described below is incorporated by reference to the appropriate exhibit numbers and the Commission file numbers indicated in parentheses, unless the reference to the document is marked as follows: * - Filed herewith. Exhibit 3 Articles of Incorporation and By-Laws * 3-1 By-Laws, as amended August 6, 1996. (Exhibit 3-1, Form 10-Q September 30, 1996, File No. 1-8222) 3-2 Articles of Association, as amended August 11, 1992. (Exhibit No. 3-2, 1992 10-K, File No. 1-8222) Exhibit 4 Instruments defining the rights of security holders, including Indentures Incorporated herein by reference: 4-1 Mortgage dated October 1, 1929, between the Company and Old Colony Trust Company, Trustee, securing the Company's First Mortgage Bonds. (Exhibit B-3, File No. 2-2364) 4-2 Supplemental Indenture dated as of August 1, 1936. (Exhibit B-4, File No. 2-2364) 4-3 Supplemental Indenture dated as of November 15, 1943. (Exhibit B-3, File No. 2-5250) 4-4 Supplemental Indenture dated as of December 1, 1943. (Exhibit No. B-4, File No. 2-5250) 4-5 Directors' resolutions adopted December 14, 1943, establishing the Series C Bonds and dealing with other related matters. (Exhibit B-5, File No. 2-5250) 4-6 Supplemental Indenture dated as of April 1, 1944. (Exhibit No. B-6, File No. 2-5466) 4-7 Supplemental Indenture dated as of February 1, 1945. (Exhibit 7.6, File No. 2-5615) (22-385) 4-8 Directors' resolutions adopted April 9, 1945, establishing the Series D Bonds and dealing with other matters. (Exhibit 7.8, File No. 2-5615 (22-385) 4-9 Supplemental Indenture dated as of September 2, 1947. (Exhibit 7.9, File No. 2-7489) 4-10 Supplemental Indenture dated as of July 15, 1948, and directors' resolutions establishing the Series E Bonds and dealing with other matters. (Exhibit 7.10, File No. 2-8388) 4-11 Supplemental Indenture dated as of May 1, 1950, and directors' resolutions establishing the Series F Bonds and dealing with other matters. (Exhibit 7.11, File No. 2-8388) 4-12 Supplemental Indenture dated August 1, 1951, and directors' resolutions, establishing the Series G Bonds and dealing with other matters. (Exhibit 7.12, File No. 2-9073) 4-13 Supplemental Indenture dated May 1, 1952, and directors' resolutions, establishing the Series H Bonds and dealing with other matters. (Exhibit 4.3.13, File No. 2-9613) 4-14 Supplemental Indenture dated as of July 10, 1953. (July, 1953 Form 8-K, File No. 1-8222) 4-15 Supplemental Indenture dated as of June 1, 1954, and directors' resolutions establishing the Series K Bonds and dealing with other matters. (Exhibit 4.2.16, File No. 2-10959) 4-16 Supplemental Indenture dated as of February 1, 1957, and directors' resolutions establishing the Series L Bonds and dealing with other matters. (Exhibit 4.2.16, File No. 2-13321) 4-17 Supplemental Indenture dated as of March 15, 1960. (March, 1960 Form 8-K, File No. 1-8222) 4-18 Supplemental Indenture dated as of March 1, 1962. (March, 1962 Form 8-K, File No. 1-8222) 4-19 Supplemental Indenture dated as of March 2, 1964. (March, 1964 Form 8-K, File No, 1-8222) 4-20 Supplemental Indenture dated as of March 1, 1965, and directors' resolutions establishing the Series M Bonds and dealing with other matters. (April, 1965 Form 8-K, File No. 1-8222) 4-21 Supplemental Indenture dated as of December 1, 1966, and directors' resolutions establishing the Series N Bonds and dealing with other matters. (January, 1967 Form 8-K, File No. 1-8222) 4-22 Supplemental Indenture dated as of December 1, 1967, and directors' resolutions establishing the Series O Bonds and dealing with other matters. (December, 1967 Form 8-K, File No. 1-8222) 4-23 Supplemental Indenture dated as of July 1, 1969, and directors' resolutions establishing the Series P Bonds and dealing with other matters. (Exhibit B.23, July, 1969 Form 8-K, File No. 1-8222) 4-24 Supplemental Indenture dated as of December 1, 1969, and directors' resolutions establishing the Series Q Bonds January, and dealing with other matters. (Exhibit B.24, January, 1970 Form 8-K, File No. 1-8222) 4-25 Supplemental Indenture dated as of May 15, 1971, and directors' resolutions establishing the Series R Bonds and dealing with other matters. (Exhibit B.25, May, 1971, Form 8-K, File No. 1-8222) 4-26 Supplemental Indenture dated as of April 15, 1973, and directors' resolutions establishing the Series S Bonds and dealing with other matters. (Exhibit B.26, May, 1973, Form 8-K, File No. 1-8222) 4-27 Supplemental Indenture dated as of April 1, 1975, and directors' resolutions establishing the Series T Bonds and dealing with other matters. (Exhibit B.27, April, 1975, Form 8-K, File No. 1-8222) 4-28 Supplemental Indenture dated as of April 1, 1977. (Exhibit 2.42, File No. 2-58621) 4-29 Supplemental Indenture dated as of July 29, 1977, and directors' resolutions establishing the Series U, V, W, and X Bonds and dealing with other matters. (Exhibit 2.43, File No. 2-58621) 4-30 Thirtieth Supplemental Indenture dated as of September 15, 1978, and directors' resolutions establishing the Series Y Bonds and dealing with other matters. (Exhibit B-30, 1980 Form 10-K, File No. 1-8222) 4-31 Thirty-first Supplemental Indenture dated as of September 1, 1979, and directors' resolutions establishing the Series Z Bonds and dealing with other matters. (Exhibit B-31, 1980 Form 10-K, File No. 1-8222) 4-32 Thirty-second Supplemental Indenture dated as of June 1, 1981, and directors' resolutions establishing the Series AA Bonds and dealing with other matters. (Exhibit B-32, 1981 Form 10-K, File No. 1-8222) 4-45 Thirty-third Supplemental Indenture dated as of August 15, 1983, and directors' resolutions establishing the Series BB Bonds and dealing with other matters. (Exhibit B-45, 1983 Form 10-K, File No. 1-8222) 4-46 Bond Purchase Agreement between Merrill, Lynch, Pierce, Fenner & Smith, Inc., Underwriters and The Industrial Development Authority of the State of New Hampshire, issuer and Central Vermont Public Service Corporation. (Exhibit B-46, 1984 Form 10-K, File No. 1-8222) 4-47 Thirty-Fourth Supplemental Indenture dated as of January 15, 1985, and directors' resolutions establishing the Series CC Bonds and Series DD Bonds and matters connected therewith. (Exhibit B-47, 1985 Form 10-K, File No. 1-8222) 4-48 Bond Purchase Agreement among Connecticut Development Authority and Central Vermont Public Service Corporation with E. F. Hutton & Company Inc. dated December 11, 1985. (Exhibit B-48, 1985 Form 10-K, File No. 1-8222) 4-49 Stock-Purchase Agreement between Vermont Electric Power Company, Inc. and the Company dated August 11, 1986 relative to purchase of Class C Preferred Stock. (Exhibit B-49, 1986 Form 10-K, File No. 1-8222) 4-50 Thirty-Fifth Supplemental Indenture dated as of December 15, 1989 and directors' resolutions establishing the Series EE, Series FF and Series GG Bonds and matters connected therewith. (Exhibit 4-50, 1989 Form 10-K, File No. 1-8222) 4-51 Thirty-Sixth Supplemental Indenture dated as of December 10, 1990 and directors' resolutions establishing the Series HH Bonds and matters connected therewith. (Exhibit 4-51, 1990 Form 10-K, File No. 1-8222) 4-52 Thirty-Seventh Supplemental Indenture dated December 10, 1991 and directors' resolutions establishing the Series JJ Bonds and matters connected therewith. (Exhibit 4-52, 1991 Form 10-K, File No. 1-8222) 4-53 Thirty-Eight Supplemental Indenture dated December 10, 1993 establishing Series KK, LL, MM, NN, OO. (Exhibit 4-53, 1993 Form 10-K, File No. 1-8222) Exhibit 10 Material Contracts (*Denotes filed herewith) Incorporated herein by reference: 10.l Copy of firm power Contract dated August 29, 1958, and supplements thereto dated September 19, 1958, October 7, 1958, and October 1, 1960, between the Company and the State of Vermont (the "State"). (Exhibit C-1, File No. 2-17184) 10.1.1 Agreement setting out Supplemental NEPOOL Understandings dated as of April 2, 1973. (Exhibit C-22, File No. 5-50198) 10.2 Copy of Transmission Contract dated June 13, 1957, between Velco and the State, relating to transmission of power. (Exhibit 10.2, 1993 Form 10-K, File No. 1-8222) 10.2.1 Copy of letter agreement dated August 4, 1961, between Velco and the State. (Exhibit C-3, File No. 2-26485) 10.2.2 Amendment dated September 23, 1969. (Exhibit C-4, File No. 2-38161) 10.2.3 Amendment dated March 12, 1980. (Exhibit C-92, 1982 Form 10-K, File No. 1-8222) 10.2.4 Amendment dated September 24, 1980. (Exhibit C-93, 1982 Form 10-K, File No. 1-8222) 10.3 Copy of subtransmission contract dated August 29, 1958, between Velco and the Company (there are seven similar contracts between Velco and other utilities). (Exhibit 10.3, 1993 Form 10-K, Form No. 1-8222) 10.3.1 Copies of Amendments dated September 7, 196l, November 2, 1967, March 22, 1968, and October 29, 1968. (Exhibit C-6, File No. 2-32917) 10.3.2 Amendment dated December 1, 1972. (Exhibit 10.3.2, 1993 Form 10-K, File No. 1-8222) 10.4 Copy of Three-Party Agreement dated September 25, 1957, between the Company, Green Mountain and Velco. (Exhibit C-7, File No. 2-17184) 10.4.1 Superseding Three Party Power Agreement dated January 1, 1990. (Exhibit 10-201, 1990 Form 10-K, File No. 1-8222) 10.4.2 Agreement Amending Superseding Three Party Power Agreement dated May 1, 1991. (Exhibit 10.4.2, 1991 Form 10-K, File No. 1-8222) 10.5 Copy of firm power Contract dated December 29, 1961, between the Company and the State, relating to purchase of Niagara Project power. (Exhibit C-8, File No. 2-26485) 10.5.1 Amendment effective as of January 1, 1980. (Exhibit 10.5.1, 1993 Form 10-K, File No. 1-8222) 10.6 Copy of agreement dated July 16, 1966, and letter supplement dated July 16, 1966, between Velco and Public Service Company of New Hampshire relating to purchase of single unit power from Merrimack II. (Exhibit C-9, File No. 2-26485) 10.6.1 Copy of Letter Agreement dated July 10, 1968, modifying Exhibit A. (Exhibit C-10, File No. 2-32917) 10.7 Copy of Capital Funds Agreement between the Company and Vermont Yankee dated as of February 1, 1968. (Exhibit C-11, File No. 70-4611) 10.7.1 Copy of Amendment dated March 12, 1968. (Exhibit C-12, File No. 70-4611) 10.7.2 Copy of Amendment dated September 1, 1993. (Exhibit 10.7.2, 1994 Form 10-K, File No. 1-8222) 10.8 Copy of Power Contract between the Company and Vermont Yankee dated as of February 1, 1968. (Exhibit C-13, File No. 70-4591) 10.8.1 Amendment dated April 15, 1983. (10.8.1, 1993 Form 10-K, File No. 1-8222) 10.8.2 Copy of Additional Power Contract dated February 1, 1984. (Exhibit C-123, 1984 Form 10-K, File No. 1-8222) 10.8.3 Amendment No. 3 to Vermont Yankee Power Contract, dated April 24, 1985. (Exhibit 10-144, 1986 Form 10-K, File No. 1-8222) 10.8.4 Amendment No. 4 to Vermont Yankee Power Contract, dated June 1, 1985. (Exhibit 10-145, 1986 Form 10-K, File No. 1-8222) 10.8.5 Amendment No. 5 dated May 6, 1988. (Exhibit 10-179, 1988 Form 10-K, File No. 1-8222) 10.8.6 Amendment No. 6 dated May 6, 1988. (Exhibit 10-180, 1988 Form 10-K, File No. 1-8222) 10.8.7 Amendment No. 7 dated June 15, 1989. (Exhibit 10-195, 1989 Form 10-K, File No. 1-8222) 10.9 Copy of Capital Funds Agreement between the Company and Maine Yankee dated as of May 20, 1968. (Exhibit C-14, File No. 70-4658) 10.9.1 Amendment No. 1 dated August 1, 1985. (Exhibit C-125, 1984 Form 10-K, File No. 1-8222) 10.10 Copy of Power Contract between the Company and Maine Yankee dated as of May 20, 1968. (Exhibit C-15, File No. 70-4658) 10.10.1 Amendment No. 1 dated March 1, 1984. (Exhibit C-112, 1984 Form 10-K, File No. 1-8222) 10.10.2 Amendment No. 2 effective January 1, 1984. (Exhibit C-113, 1984 Form 10-K, File No. 1-8222) 10.10.3 Amendment No. 3 dated October 1, 1984. (Exhibit C-114, 1984 Form 10-K, File No. 1-8222) 10.10.4 Additional Power Contract dated February 1, 1984. (Exhibit C-126, 1985 Form 10-K, File No. 1-8222) 10.11 Copy of Agreement dated January 17, 1968, between Velco and Public Service Company of New Hampshire relating to purchase of additional unit power from Merrimack II. (Exhibit C-16, File No. 2-32917) 10.12 Copy of Agreement dated February 10, 1968 between the Company and Velco relating to purchase by Company of Merrimack II unit power. (There are 25 similar agreements between Velco and other utilities.) (Exhibit C-17, File No. 2-32917) 10.13 Copy of Three-Party Power Agreement dated as of November 21, 1969, among the Company, Velco, and Green Mountain relating to purchase and sale of power from Vermont Yankee Nuclear Power Corporation. (Exhibit C-18, File No. 2-38161) 10.13.1 Amendment dated June 1, 1981. (Exhibit 10.13.1, 1993 Form 10-K, File No. 1-8222) 10.14 Copy of Three-Party Transmission Agreement dated as of November 21, 1969, among the Company, Velco, and Green Mountain providing for transmission of power from Vermont Yankee Nuclear Power Corporation. (Exhibit C-19, File No. 2-38161) 10.14.1 Amendment dated June 1, 1981. (Exhibit 10.14.1, 1993 Form 10-K, File No. 1-8222) 10.15 Copy of Stockholders Agreement dated September 25, 1957, between the Company, Velco, Green Mountain and Citizens Utilities Company. (Exhibit No. C-20, File No. 70-3558) 10.16 New England Power Pool Agreement dated as of September 1, 1971, as amended to November 1, 1975. (Exhibit C-21, File No. 2-55385) 10.16.1 Amendment dated December 31, 1976. (Exhibit 10.16.1 1993 Form 10-K, File No. 1-8222) 10.16.2 Amendment dated January 23, 1977. (Exhibit 10.16.2, 1993 Form 10-K, File No. 1-8222) 10.16.3 Amendment dated July 1, 1977. (Exhibit 10.16.3, 1993 Form 10-K, File No. 1-8222) 10.16.4 Amendment dated August 1, 1977. (Exhibit 10.16.4, 1993 Form 10-K, File No. 1-8222) 10.16.5 Amendment dated August 15, 1978. (Exhibit 10.16.5, 1993 Form 10-K, File No. 1-8222) 10.16.6 Amendment dated January 31, 1979. (Exhibit 10.16.6, 1993 Form 10-K, File No. 1-8222) 10.16.7 Amendment dated February 1, 1980. (Exhibit 10.16.7, 1993 Form 10-K, File No. 1-8222) 10.16.8 Amendment dated December 31, 1976. (Exhibit 10.16.8, 1993 Form 10-K, File No. 1-8222) 10.16.9 Amendment dated January 31, 1977. (Exhibit 10.16.9, 1993 Form 10-K, File No. 1-8222) 10.16.10 Amendment dated July 1, 1977. (Exhibit 10.16.10, 1993 Form 10-K, File No. 1-8222) 10.16.11 Amendment dated August 1, 1977. (Exhibit 10.16.11, 1993 Form 10-K, File No. 1-8222) 10.16.12 Amendment dated August 15, 1978. (Exhibit 10.16.12, 1993 Form 10-K, File No. 1-8222) 10.16.13 Amendment dated January 31, 1980. (Exhibit 10.16.13, 1993 Form 10-K, File No. 1-8222) 10.16.14 Amendment dated February 1, 1980. (Exhibit 10.16.14, 1993 Form 10-K, File No. 1-8222) 10.16.15 Amendment dated September 1, 1981. (Exhibit 10.16.15, 1993 Form 10-K, File No. 1-8222) 10.16.16 Amendment dated December 1, 1981. (Exhibit 10.16.16, 1993 Form 10-K, File No. 1-8222) 10.16.17 Amendment dated June 15, 1983. (Exhibit 10.16.17, 1993 Form 10-K, File No. 1-8222) 10.16.18 Amendment dated September 1, 1985. (Exhibit 10-160, 1986 Form 10-K, File No. 1-8222) 10.16.19 Amendment dated April 30, 1987. (Exhibit 10-172, 1987 Form 10-K, File No. 1-8222) 10.16.20 Amendment dated March 1, 1988. (Exhibit 10-178, 1988 Form 10-K, File No. 1-8222) 10.16.21 Amendment dated March 15, 1989. (Exhibit 10-194, 1989 Form 10-K, File No. 1-8222) 10.16.22 Amendment dated October 1, 1990. (Exhibit 10-203, 1990 Form 10-K, File No. 1-8222) 10.16.23 Amendment dated September 15, 1992. (Exhibit 10.16.23, 1992 Form 10-K, File No. 1-8222) 10.16.24 Amendment dated May 1, 1993. (Exhibit 10.16.24, 1993 Form 10-K, File No. 1-8222) 10.16.25 Amendment dated June 1, 1993. (Exhibit 10.16.25, 1993 Form 10-K, File No. 1-8222) 10.16.26 Amendment dated June 1, 1994. (Exhibit 10.16.26, 1994 Form 10-K, File No. 1-8222) 10.16.27 Thirty-Second Amendment dated September 1, 1995. (Exhibit 10.16.27, Form 10-Q dated September 30, 1995, File No. 1-8222 and Exhibit 10.16.27, 1995 Form 10-K, File No. 1-8222) 10.17 Agreement dated October 13, 1972, for Joint Ownership, Construction and Operation of Pilgrim Unit No. 2 among Boston Edison Company and other utilities, including the Company. (Exhibit C-23, File No. 2-45990) 10.17.1 Amendments dated September 20, 1973, and September 15, 1974. (Exhibit C-24, File No. 2-51999) 10.17.2 Amendment dated December 1, 1974. (Exhibit C-25, File No. 2-54449) 10.17.3 Amendment dated February 15, 1975. (Exhibit C-26, File No. 2-53819) 10.17.4 Amendment dated April 30, 1975. (Exhibit C-27, File No. 2-53819) 10.17.5 Amendment dated as of June 30, 1975. (Exhibit C-28, File No. 2-54449) 10.17.6 Instrument of Transfer dated as of October 1, 1974, assigning partial interest from the Company to Green Mountain Power Corporation. (Exhibit C-29, File No. 2-52177) 10.17.7 Instrument of Transfer dated as of January 17, 1975, assigning a partial interest from the Company to the Burlington Electric Department. (Exhibit C-30, File No. 2-55458) 10.17.8 Addendum dated as of October 1, 1974 by which Green Mountain Power Corporation became a party thereto. (Exhibit C-31, File No. 2-52177) 10.17.9 Addendum dated as of January 17, 1975 by which the Burlington Electric Department became a party thereto. (Exhibit C-32, File No. 2-55450) 10.17.10 Amendment 23 dated as of 1975. (Exhibit C-50, 1975 Form 10-K, File No. 1-8222) 10.18 Agreement for Sharing Costs Associated with Pilgrim Unit No.2 Transmission dated October 13, 1972, among Boston Edison Company and other utilities including the Company. (Exhibit C-33, File No. 2-45990) 10.18.1 Addendum dated as of October 1, 1974, by which Green Mountain Power Corporation became a party thereto. (Exhibit C-34, File No. 2-52177) 10.18.2 Addendum dated as of January 17, 1975, by which Burlington Electric Department became a party thereto. (Exhibit C-35, File No. 2-55458) 10.19 Agreement dated as of May 1, 1973, for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units among Public Service Company of New Hampshire and other utilities, including Velco. (Exhibit C-36, File No. 2-48966) 10.19.1 Amendments dated May 24, 1974, June 21, 1974, September 25, 1974, October 25, 1974, and January 31, 1975. (Exhibit C-37, File No. 2-53674) 10.19.2 Instrument of Transfer dated September 27, 1974, assigning partial interest from Velco to the Company. (Exhibit C-38, File No. 2-52177) 10.19.3 Amendments dated May 24, 1974, June 21, 1974, and September 25, 1974. (Exhibit C-81, File No. 2-51999) 10.19.4 Amendments dated October 25, 1974 and January 31, 1975. (Exhibit C-82, File No. 2-54646) 10.19.5 Sixth Amendment dated as of April 18, 1979. (Exhibit C-83, File No. 2-64294) 10.19.6 Seventh Amendment dated as of April 18, 1979. (Exhibit C-84, File No. 2-64294) 10.19.7 Eighth Amendment dated as of April 25, 1979. (Exhibit C-85, File No. 2-64815) 10.19.8 Ninth Amendment dated as of June 8, 1979. (Exhibit C-86, File No. 2-64815) 10.19.9 Tenth Amendment dated as of October 10, 1979. (Exhibit C-87, File No. 2-66334 ) 10.19.10 Eleventh Amendment dated as of December 15, 1979. (Exhibit C-88, File No.2-66492) 10.19.11 Twelfth Amendment dated as of June 16, 1980. (Exhibit C-89, File No. 2-68168) 10.19.12 Thirteenth Amendment dated as of December 31, 1980. (Exhibit C-90, File No. 2-70579) 10.19.13 Fourteenth Amendment dated as of June 1, 1982.(Exhibit C-104, 1982 Form 10-K, File No. 1-8222) 10.19.14 Fifteenth Amendment dated April 27, 1984. (Exhibit 10-134, 1986 Form 10-K, File No. 1-8222) 10.19.15 Sixteenth Amendment dated June 15, 1984. (Exhibit 10-135, 1986 Form 10-K, File No. 1-8222) 10.19.16 Seventeenth Amendment dated March 8, 1985. (Exhibit 10-136, 1986 Form 10-K, File No. 1-8222) 10.19.17 Eighteenth Amendment dated March 14, 1986. (Exhibit 10-137, 1986 Form 10-K, File No. 1-8222) 10.19.18 Nineteenth Amendment dated May 1, 1986. (Exhibit 10-138, 1986 Form 10-K, File No. 1-8222) 10.19.19 Twentieth Amendment dated September 19, 1986. (Exhibit 10-139, 1986 Form 10-K, File No. 1-8222) 10.19.20 Amendment No. 22 dated January 13, 1989. (Exhibit 10-193, 1989 Form 10-K, File No. 1-8222) 10.20 Transmission Support Agreement dated as of May 1, 1973, among Public Service Company of New Hampshire and other utilities, including Velco, with respect to New Hampshire Nuclear Units. (Exhibit C-39, File No. 248966) 10.21 Sharing Agreement - 1979 Connecticut Nuclear Unit dated September 1, 1973, to which the Company is a party. (Exhibit C-40, File No. 2-50142) 10.21.1 Amendment dated as of August 1, 1974. (Exhibit C-41, File No. 2-51999) 10.21.2 Instrument of Transfer dated as of February 28, 1974, transferring partial interest from the Company to Green Mountain. (Exhibit C-42, File No. 2-52177) 10.21.3 Instrument of Transfer dated January 17, 1975, transferring a partial interest from the Company to Burlington Electric Department. (Exhibit C-43, File No. 2-55458) 10.21.4 Amendment dated May 11, 1984. (Exhibit C-110, 1984 Form 10-K, File No. 1-8222) 10.22 Preliminary Agreement dated as of July 5, 1974, with respect to 1981 Montague Nuclear Generating Units. (Exhibit C-44, File No. 2-51733) 10.22.1 Amendment dated June 30, 1975. (Exhibit C-45, File No. 2-54449) 10.23 Agreement for Joint Ownership, Construction and Operation of William F. Wyman Unit No. 4 dated November 1, 1974, among Central Maine Power Company and other utilities including the Company. (Exhibit C-46, File No. 2-52900) 10.23.1 Amendment dated as of June 30, 1975. (Exhibit C-47, File No. 2-55458) 10.23.2 Instrument of Transfer dated July 30, 1975, assigning a partial interest from Velco to the Company. (Exhibit C-48, File No. 2-55458) 10.24 Transmission Agreement dated November 1, 1974, among Central Maine Power Company and other utilities including the Company with respect to William F. Wyman Unit No. 4. (Exhibit C-49, File No. 2-54449) 10.25 Copy of Power Contract between the Company and Yankee Atomic dated as of June 30, 1959. (Exhibit C-61, 1981 Form 10-K, File No. 1-8222) 10.25.1 Revision dated April 1, 1975. (Exhibit C-61, 1981 Form 10-K, File No. 1-8222) 10.25.2 Amendment dated May 6, 1988. (Exhibit 10-181, 1988 Form 10-K, File No. 1-8222) 10.25.3 Amendment dated June 26, 1989. (Exhibit 10-196, 1989 Form 10-K, File No. 1-8222) 10.25.4 Amendment dated July 1, 1989. (Exhibit 10-197, 1989 Form 10-K, File No. 1-8222) 10.25.5 Amendment dated February 1, 1992 (Exhibit 10.25.5, 1992 Form 10-K, File No. 1-8222) 10.26 Copy of Transmission Contract between the Company and Yankee Atomic dated as of June 30, 1959. (Exhibit C-63, 1981 Form 10-K, File No. 1-8222) 10.27 Copy of Power Contract between the Company and Connecticut Yankee dated as of June 1, 1964. (Exhibit C-64, 1981 Form 10-K, File No. 1-8222) 10.27.1 Supplementary Power Contract dated March 1, 1978. (Exhibit C-94, 1982 Form 10-K, File No. 1-8222) 10.27.2 Amendment dated August 22, 1980. (Exhibit C-95, 1982 Form 10-K, File No. 1-8222) 10.27.3 Amendment dated October 15, 1982. (Exhibit C-96, 1982 Form 10-K, File No. 1-8222) 10.27.4 Second Supplementary Power Contract dated April 30, 1984. (Exhibit C-115, 1984 Form 10-K, File No. 1-8222) 10.27.5 Additional Power Contract dated April 30, 1984. (Exhibit C-116, 1984 Form 10-K, File No. 1-8222) 10.28 Copy of Transmission Contract between the Company and Connecticut Yankee dated as of July 1, 1964. (Exhibit C-65, 1981 Form 10-K, File No. 1-8222) 10.29 Copy of Capital Funds Agreement between the Company and Connecticut Yankee dated as of July 1, 1964. (Exhibit C-66, 1981 Form 10-K, File No. 1-8222) 10.29.1 Copy of Capital Funds Agreement between the Company and Connecticut Yankee dated as of September 1, 1964. (Exhibit C-67, 1981 Form 10-K, File No. 1-8222) 10.30 Copy of Five-Year Capital Contribution Agreement between the Company and Connecticut Yankee dated as of November 1, 1980. (Exhibit C-68, 1981 Form 10-K, File No. 1-8222) 10.31 Form of Guarantee Agreement dated as of November 7, 1981, among certain banks, Connecticut Yankee and the Company, relating to revolving credit notes of Connecticut Yankee. (Exhibit C-69, 1981 Form 10-K, File No. 1-8222) 10.32 Form of Guarantee Agreement dated as of November 13, 1981, between The Connecticut Bank and Trust Company, as Trustee, and the Company, relating to debentures of Connecticut Yankee. (Exhibit C-70, 1981 Form 10-K, File No. 1-8222) 10.33 Form of Guarantee Agreement dated as of November 5, 1981, between Bankers Trust Company, as Trustee of the Vernon Energy Trust, and the Company, relating to Vermont Yankee Nuclear Fuel Sale Agreement. (Exhibit C-71, 1981 Form 10-K, File No. 1-8222) 10.34 Preliminary Vermont Support Agreement re Quebec Interconnection between Velco and among seventeen Vermont Utilities dated May 1, 1981. (Exhibit C-97, 1982 Form 10-K, File No. 1-8222) 10.34.1 Amendment dated June 1, 1982. (Exhibit C-98, 1982 Form 10-K, File No. 1-8222) 10.35 Vermont Participation Agreement for Quebec Interconnection between Velco and among seventeen Vermont Utilities dated July 15, 1982. (Exhibit C-99, 1982 Form 10-K, File No. 1-8222) 10.35.1 Amendment No. 1 dated January 1, 1986. (Exhibit C-132, 1986 Form 10-K, File No. 1-8222) 10.36 Vermont Electric Transmission Company Capital Funds Support Agreement between Velco and among sixteen Vermont Utilities dated July 15, 1982. (Exhibit C-100, 1982 Form 10-K, File No. 1-8222) 10.37 Vermont Transmission Line Support Agreement, Vermont Electric Transmission Company and twenty New England Utilities dated December 1, 1981, as amended by Amendment No. 1 dated June 1, 1982, and by Amendment No. 2 dated November 1, 1982. (Exhibit C-101, 1982 Form 10-K, File No. 1-8222) 10.37.1 Amendment No. 3 dated January 1, 1986. (Exhibit 10-149, 1986 Form 10-K, File No. 1-8222) 10.38 Phase 1 Terminal Facility Support Agreement between New England Electric Transmission Corporation and twenty New England Utilities dated December 1, 1981, as amended by Amendment No. 1 dated as of June 1, 1982 and by Amendment No. 2 dated as of November 1, 1982. (Exhibit C-102, 1982 Form 10-K, File No. 1-8222) 10.39 Power Purchase Agreement between Velco and CVPS dated June 1, 1981. (Exhibit C-103, 1982 Form 10-K, File No. 1-8222) 10.40 Agreement for Joint Ownership, Construction and Operation of the Joseph C. McNeil Generating Station by and between City of Burlington Electric Department, Central Vermont Realty, Inc. and Vermont Public Power Supply Authority dated May 14, 1982. (Exhibit C-107, 1983 Form 10-K, File No. 1-8222) 10.40.1 Amendment No. 1 dated October 5, 1982. (Exhibit C-108, 1983 Form 10-K, File No. 1-8222) 10.40.2 Amendment No. 2 dated December 30, 1983. (Exhibit C-109, 1983 Form 10-K, File No. 1-8222) 10.40.3 Amendment No. 3 dated January 10, 1984. (Exhibit 10-143, 1986 Form 10-K, File No. 1-8222) 10.41 Transmission Service Contract between Central Vermont Public Service Corporation and The Vermont Electric Generation & Transmission Cooperative, Inc. dated May 14, 1984. (Exhibit C-111, 1984 Form 10-K, File No. 1-8222) 10.42 Copy of Highgate Transmission Interconnection Preliminary Support Agreement dated April 9, 1984. (Exhibit C-117, 1984 Form 10-K, File No. 1-8222) 10.43 Copy of Allocation Contract for Hydro-Quebec Firm Power dated July 25, 1984. (Exhibit C-118, 1984 Form 10-K, File No. 1-8222) 10.43.1 Tertiary Energy for Testing of the Highgate HVDC Station Agreement, dated September 20, 1985. (Exhibit C-129, 1985 Form 10-K, File No. 1-8222) 10.44 Copy of Highgate Operating and Management Agreement dated August 1, 1984. (Exhibit C-119, 1986 Form 10-K, File No. 1-8222) 10.44.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-152, 1986 Form 10-K, File No. 1-8222) 10.44.2 Amendment No. 2 dated November 13, 1986. (Exhibit 10-167, 1987 Form 10-K, File No. 1-8222) 10.44.3 Amendment No. 3 dated January 1, 1987. (Exhibit 10-168, 1987 Form 10-K, File No. 1-8222) 10.45 Copy of Highgate Construction Agreement dated August 1, 1984. (Exhibit C-120, 1984 Form 10-K, File No. 1-8222) 10.45.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-151, 1986 Form 10-K, File No. 1-8222) 10.46 Copy of Agreement for Joint Ownership, Construction and Operation of the Highgate Transmission Interconnection. (Exhibit C-121, 1984 Form 10-K, File No. 1-8222) 10.46.1 Amendment No. 1 dated April 1, 1985. (Exhibit 10-153, 1986 Form 10-K, File No. 1-8222) 10.46.2 Amendment No. 2 dated April 18, 1985. (Exhibit 10-154, 1986 Form 10-K, File No. 1-8222) 10.46.3 Amendment No. 3 dated February 12, 1986. (Exhibit 10-155, 1986 Form 10-K, File No. 1-8222) 10.46.4 Amendment No. 4 dated November 13, 1986. (Exhibit 10-169, 1987 Form 10-K, File No. 1-8222) 10.46.5 Amendment No. 5 and Restatement of Agreement dated January 1, 1987. (Exhibit 10-170, 1987 Form 10-K, File No. 1-8222) 10.47 Copy of the Highgate Transmission Agreement dated August 1, 1984. (Exhibit C-122, 1984 Form 10-K, File No. 1-8222) 10.48 Copy of Preliminary Vermont Support Agreement Re: Quebec Interconnection - Phase II dated September 1, 1984. (Exhibit C-124, 1984 Form 10-K, File No. 1-8222) 10.48.1 First Amendment dated March 1, 1985. (Exhibit C-127, 1985 Form 10-K, File No. 1-8222) 10.49 Vermont Transmission and Interconnection Agreement between New England Power Company and Central Vermont Public Service Corporation and Green Mountain Power Corporation with the consent of Vermont Electric Power Company, Inc., dated May 1, 1985. (Exhibit C-128, 1985 Form 10-K, File No. 1-8222) 10.50 Service Contract Agreement between the Company and the State of Vermont for distribution and sale of energy from St. Lawrence power projects ("NYPA Power") dated as of June 25, 1985. (Exhibit C-130, 1985 Form 10-K, File No. 1-8222) 10.50.1 Lease and Operating Agreement between the Company and the State of Vermont dated as of June 25, 1985. (Exhibit C-131, 1985 Form 10-K, File No. 1-8222) 10.51 System Sales & Exchange Agreement Between Niagara Mohawk Power Corporation and Central Vermont Public Service Corporation dated October 1, 1986. (Exhibit C-133, 1986 Form 10-K, File No. 1-8222) 10.54 Transmission Agreement between Vermont Electric Power Company, Inc. and Central Vermont Public Service Corporation dated January 1, 1986. (Exhibit 10-146, 1986 Form 10-K, File No. 1-8222) 10.55 1985 Four-Party Agreement between Vermont Electric Power Company, Central Vermont Public Service Corporation, Green Mountain Power Corporation and Citizens Utilities dated July 1, 1985. (Exhibit 10-147, 1986 Form 10-K, File No. 1-8222) 10.55.1 Amendment dated February 1, 1987. (Exhibit 10-171, 1987 Form 10-K, File No. 1-8222) 10.56 1985 Option Agreement between Vermont Electric Power Company, Central Vermont Public Service Corporation, Green Mountain Power Corporation and Citizens Utilities dated December 27, 1985. (Exhibit 10-148, 1986 Form 10-K, File No. 1-8222) 10.56.1 Amendment No. 1 dated September 28, 1988. (Exhibit 10-182, 1988 Form 10-K, File No. 1-8222) 10.56.2 Amendment No. 2 dated October 1, 1991. (Exhibit 10.56.2, 1991 Form 10-K, File No. 1-8222) 10.56.3 Amendment No. 3 dated December 31, 1994. (Exhibit 10.56.3, 1994 Form 10-K, File No. 1-8222) * 10.56.4 Amendment No. 4 dated December 31, 1996. 10.57 Highgate Transmission Agreement dated August 1, 1984 by and between the owners of the project and the Vermont electric distribution companies. (Exhibit 10-156, 1986 Form 10-K, File No. 1-8222) 10.57.1 Amendment No. 1 dated September 22, 1985. (Exhibit 10-157, 1986 Form 10-K, File No. 1-8222) 10.58 Vermont Support Agency Agreement re: Quebec Interconnection - Phase II between Vermont Electric Power Company, Inc. and participating Vermont electric utilities dated June 1, 1985. (Exhibit 10-158, 1986 Form 10K, File No. 1-8222) 10.58.1 Amendment No. 1 dated June 20, 1986. (Exhibit 10-159, 1986 Form 10-K, File No. 1-8222) 10.59 Indemnity Agreement B-39 dated May 9, 1969 with amendments 1-16 dated April 17, 1970 thru April 16, 1985 between licensees of Millstone Unit No. 3 and the Nuclear Regulatory Commission. (Exhibit 10-161, 1986 Form 10-K, File No. 1-8222) 10.59.1 Amendment No. 17 dated November 25, 1985. (Exhibit 10-162, 1986 Form 10-K, File No. 1-8222) 10.62 Contract for the Sale of 50MW of firm power between Hydro-Quebec and Vermont Joint Owners of Highgate Facilities dated February 23, 1987. (Exhibit 10-173, 1987 Form 10-K, File No. 1-8222) 10.63 Interconnection Agreement between Hydro-Quebec and Vermont Joint Owners of Highgate facilities dated February 23, 1987. (Exhibit 10-174, 1987 Form 10-K, File No. 1-8222) 10.63.1 Amendment dated September 1, 1993 (Exhibit 10.63.1, 1993 Form 10-K, File No. 1-8222) 10.64 Firm Power and Energy Contract by and between Hydro-Quebec and Vermont Joint Owners of Highgate for 500MW dated December 4, 1987. (Exhibit 10-175, 1987 Form 10-K, File No. 1-8222) 10.64.1 Amendment No. 1 dated August 31, 1988. (Exhibit 10-191, 1988 Form 10-K, File No. 1-8222) 10.64.2 Amendment No. 2 dated September 19, 1990. (Exhibit 10-202, 1990 Form 10-K, File No. 1-8222) 10.64.3 Firm Power & Energy Contract dated January 21, 1993 by and between Hydro-Quebec and Central Vermont Public Service Corporation for the sale back of 25 MW of power. (Exhibit 10.64.3, 1992 Form 10-K, File No. 1-8222) 10.64.4 Firm Power & Energy Contract dated January 21, 1993 by and between Hydro-Quebec and Central Vermont Public Service Corporation for the sale back of 50 MW of power. (Exhibit 10.64.4, 1992 Form 10-K, File No. 1-8222) 10.66 Hydro-Quebec Participation Agreement dated April 1, 1988 for 600 MW between Hydro-Quebec and Vermont Joint Owners of Highgate. (Exhibit 10-177, 1988 Form 10-K, File No. 1-8222) 10.67 Sale of firm power and energy (54MW) between Hydro-Quebec and Vermont Utilities dated December 29, 1988. (Exhibit 10-183, 1988 Form 10-K, File No. 1-8222) 10.75 Receivables Purchase Agreement between Central Vermont Public Service Corporation, Central Vermont Public Service Corporation as Service Agent and The First National Bank of Boston dated November 29, 1988. (Exhibit 10-192, 1988 Form 10-K) 10.75.1 Agreement Amendment No. 1 dated December 21, 1988 (Exhibit 10.75.1, 1993 Form 10-K, File No. 1-8222) 10.75.2 Letter Agreement dated December 4, 1989 (Exhibit 10.75.2, 1993 Form 10-K, File No. 1-8222) 10.75.3 Agreement Amendment No. 2 dated November 29, 1990 (Exhibit 10.75.3, 1993 Form 10-K, File No. 1-8222) 10.75.4 Agreement Amendment No. 3 dated November 29, 1991 (Exhibit 10.75.4, 1993 Form 10-K, File No. 1-8222) 10.75.5 Agreement Amendment No. 4 dated November 29, 1992 (Exhibit 10.75.5, 1993 Form 10-K, File No. 1-8222) EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS A 10.68 Stock Option Plan for Non-Employee Directors dated July 18, 1988. (Exhibit 10-184, 1988 Form 10-K, File No. 1-8222) A 10.69 Stock Option Plan for Key Employees dated July 18, 1988. (Exhibit 10-185, 1988 Form 10-K, File No. 1-8222) A 10.70 Officers Supplemental Insurance Plan authorized July 9, 1984. (Exhibit 10-186, 1988 Form 10-K, File No. 1-8222) A 10.71 Officers Supplemental Deferred Compensation Plan dated November 4, 1985. (Exhibit 10-187, 1988 Form 10-K, File No. 1-8222) A 10.71.1 Amendment dated October 2, 1995. (Exhibit 10.71.1, 1995 Form 10-K, File No. 1-8222) A 10.72 Directors' Supplemental Deferred Compensation Plan dated November 4, 1985. (Exhibit 10-188, 1988 Form 10-K, File No. 1-8222) A 10.72.1 Amendment dated October 2, 1995. (Exhibit 10.72.1, 1995 Form 10-K, File No. 1-8222) A 10.73 Management Incentive Compensation Plan as adopted September 9, 1985. (Exhibit 10-189, 1988 Form 10-K, File No. 1-8222) A 10.73.1 Revised Management Incentive Plan as adopted February 5, 1990. (Exhibit 10-200, 1989 Form 10-K, File No. 1-8222) A 10.73.2 Revised Management Incentive Plan dated May 2, 1995. (Exhibit 10.73.2, 1995 Form 10-K, File No. 1-8222) A 10.74 Officers' Change of Control Agreements as approved October 3, 1988. (Exhibit 10-190, 1988 Form 10-K, File No. 1-8222) A 10.78 Stock Option Plan for Non-Employee Directors dated April 30, 1993 (Exhibit 10.78, 1993 Form 10-K, File No. 1-8222) A 10.79 Officers Insurance Plan dated November 15, 1993 (Exhibit 10.79, 1993 Form 10-K, File No. 1-8222) A 10.79.1 Amendment dated October 2, 1995. (Exhibit No. 10.79.1, 1995 Form 10-K, File No. 1-8222) A 10.80 Directors' Supplemental Deferred Compensation Plan dated January 1, 1990 (Exhibit 10.80, 1993 Form 10-K, File No. 1-8222) A 10.80.1 Amendment dated October 2, 1995. (Exhibit No. 10.80.1, 1995 Form 10-K, File No. 1-8222) A 10.81 Officers' Supplemental Deferred Compensation Plan dated January 1, 1990 (Exhibit 10.81, 1993 Form 10-K, File No. 1-8222) *A 10.82 Management Incentive Plan for Executive Officers dated January 1, 1997. A - Compensation related plan, contract, or arrangement. 21. Subsidiaries of the Registrant * 21.1 List of Subsidiaries of Registrant 23. Consents of Experts and Counsel * 23.1 Consent of Independent Public Accountants 27. Financial Data Schedule (filed electronically only) (b) Reports on Form 8-K: The Company filed no reports on Form 8-K during the quarter ended December 31, 1996. Report of Independent Public Accountants To the Board of Directors of Central Vermont Public Service Corporation: We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements included in Central Vermont Public Service Corporation's annual report to shareholders, included in this Form 10-K, and have issued our report thereon dated February 3, 1997. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedule listed in the index above is the responsibility of the Company's management and is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly state, in all material respects, the consolidated financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. ARTHUR ANDERSEN LLP Boston, Massachusetts February 3, 1997
Schedule II CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES Reserves Year ended December 31, 1996 Additions Balance at Charged to Charged Balance at beginning costs and to other end of of year expenses accounts Deductions year ---------- ---------- -------- ---------- ---------- Reserves deducted from assets to which they apply: Reserve for uncollectible $ 81,367(1) accounts receivable 299,244(2) -------- $1,551,606 $670,083 $380,611 $1,470,105(3) $1,132,195 ========== ======== ======== ========== ========== Accumulated depreciation of miscellaneous properties: Rental water heater program $3,508,493 $356,274 - $ 311,618(4) $3,553,149 Other 295,765 436,127 - - 731,892 ---------- -------- ---------- ---------- $3,804,258 $792,401 $ 311,618 $4,285,041 ========== ======== ========== ========== Reserve shown separately: Injuries and damages reserve $ 225,580 - - - $ 225,580 ========== ========== (1) Amount due from collection agency. (2) Collections of accounts previously written off. (3) Uncollectible accounts written off. (4) Retirements of rental water heaters.
Schedule II CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES Reserves Year ended December 31, 1995 Additions Balance at Charged to Charged Balance at beginning costs and to other end of of year expenses accounts Deductions year ---------- ---------- -------- ---------- ---------- Reserves deducted from assets to which they apply: $ 80,978(1) Reserve for uncollectible 644,277(2) accounts receivable 200,000(3) -------- $ 967,732 $1,074,327 $925,255 $1,415,708(4) $1,551,606 ========== ========== ======== ========== ========== Accumulated depreciation of miscellaneous properties: Rental water heater program $3,450,284 $ 350,522 - $ 292,313(5) $3,508,493 Other 213,287 82,478 - - 295,765 ---------- ---------- --------- ---------- $3,663,571 $ 433,000 $ 292,313 $3,804,258 ========== ========== ========= ========== Reserve shown separately: Injuries and damages reserve $ 225,580 - - - $ 225,580 ========== ========== (1) Amount due from collection agency. (2) Collections of accounts previously written off. (3) Transferred from miscellaneous receivables. (4) Uncollectible accounts written off. (5) Retirements of rental water heaters.
Schedule II CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES Reserves Year ended December 31, 1994 Additions Balance at Charged to Charged Balance at beginning costs and to other end of of year expenses accounts Deductions year ---------- ---------- -------- ---------- ---------- Reserves deducted from assets to which they apply: Reserve for uncollectible $ 71,210(1) accounts receivable 335,718(2) -------- $ 936,080 $547,490 $406,928 $ 922,766(3) $ 967,732 ========== ======== ======== ========== ========== Accumulated depreciation of miscellaneous properties: Rental water heater program $3,428,944 $265,309 - $ 243,969(4) $3,450,284 Other 68,153 145,134(5) - - 213,287 ---------- -------- ---------- ---------- $3,497,097 $410,443 $ 243,969 $3,663,571 ========== ======== ========== ========== Reserve shown separately: Injuries and damages reserve $ 225,580 - - - $ 225,580 ========== ========== (1) Amount due from collection agency. (2) Collections of accounts previously written off. (3) Uncollectible accounts written off. (4) Retirements of rental water heaters. (5) Includes reclassification of $67,201 of the Company's wholly owned subsidiary, SmartEnergy Services, Inc.'s depreciation expense from its water heater program to other non-utility property.
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CENTRAL VERMONT PUBLIC SERVICE CORPORATION By /s/ Robert H. Young ------------------------------ Robert H. Young, President and Chief Executive Officer March 25, 1997 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. DATE NAME AND TITLE _________________ _________________________________________ March 25, 1997 /s/ Robert H. Young ---------------------------------------- Robert H. Young President and Chief Executive Officer and Director March 25, 1997 /s/ Francis J. Boyle ---------------------------------------- Francis J. Boyle, Vice President - Finance and Administration and Chief Financial Officer (Principal Financial Officer) March 25, 1997 /s/ James M. Pennington ---------------------------------------- James M. Pennington, Controller (Principal Accounting Officer) March 25, 1997 /s/ F. Ray Keyser, Jr. ---------------------------------------- F. Ray Keyser, Jr. Chairman of the Board and Director March 25, 1997 /s/ Robert L. Barnett ---------------------------------------- Robert L. Barnett Director March 25, 1997 /s/ Frederic H. Bertrand ---------------------------------------- Frederic H. Bertrand Director March 25, 1997 /s/ Rhonda L. Brooks ---------------------------------------- Rhonda L. Brooks Director March 25, 1997 /s/ Luther F. Hackett ---------------------------------------- Luther F. Hackett Director March 25, 1997 /s/ Mary Alice McKenzie ---------------------------------------- Mary Alice McKenzie Director March 25, 1997 /s/ Preston Leete Smith ---------------------------------------- Preston Leete Smith Director EX-3 2 EXHIBIT 3-1 Exhibit 3-1 ------------- BY-LAWS OF CENTRAL VERMONT PUBLIC SERVICE CORPORATION ARTICLE I. Articles of Agreement: Offices Section 1. These By-Laws shall be subject to the Articles of Association, and all references in these By-Laws to the Articles of Association shall be construed to mean the Articles of Association of the Corporation as from time to time amended. Section 2. The Corporation shall maintain its principal office in Rutland, Vermont, and may maintain offices at such other places as the Board of Directors may, from time to time, appoint. ARTICLE II. Seal The corporate seal shall be circular in form and shall have inscribed thereon the name of the Corporation and the words and figures: "Seal Vermont 1929". ARTICLE III. Capital Stock and Transfers Section 1. The amount and classes of capital stock that may be issued by the Corporation, and the designations, preferences, rights, privileges, voting powers, restrictions, and qualifications of each class thereof, shall be as set forth in the Articles of Association, as the same shall at any time be duly recorded in the office of the Secretary of State of Vermont in original or amended form. Section 2. Each holder of fully paid stock shall be entitled to a certificate or certificates of stock as provided by law and in a form approved by the Board of Directors. (As amended May 2, 1972) Section 3. Shares of stock may be transferred by the owner by a proper endorsement upon the back of the certificate or by a separate instrument of assignment, and the assignee, upon producing, and surrendering the former certificate so transferred or the certificate accompanied by such instrument, shall be entitled to a new certificate if no liens upon the stock against the former owner have attached. The delivery of a properly executed stock certificate to a bona fide purchaser or pledgee for value to sell, assign and transfer the same, signed by the owner of the certificate, shall be a sufficient delivery to transfer the title against all persons except the Company; but no such transfer shall affect the right of the Company to treat the stockholder of record as the stockholder in fact until the old certificate is surrendered and a new certificate is issued to the person entitled thereto. Except as hereinafter provided, or as may be required by law or by the order of a court in appropriate proceedings, shares of stock shall be transferred on the books of the Company only upon the proper assignment and surrender of the certificates issued therefor. If an outstanding certificate of stock shall be lost, destroyed or stolen, the holder thereof may have a replacement certificate issued upon such terms as the Directors may prescribe. (As amended May 2, 1972) Section 4. If default shall be made in the prompt payment when due of any sum payable to the Company upon any subscription for stock of the Company, and if such default shall continue for a period of twenty days, then all right under the subscription in and to the stock subscribed for shall, upon the expiration of such period, cease and determine and become and be forfeited to the Company; provided that if at the expiration of such twenty day period such right shall belong to the estate of a decedent, it may be forfeited only by resolution of the Board of Directors declaring forfeiture. (As amended May 2, 1972) ARTICLE IV. Meetings of Stockholders Section 1. All meetings of the stockholders shall be held in Vermont, either at the principal office of the Company or at such other place as shall be designated in the call therefor. The annual meeting shall be held on the first Tuesday of May in each year, if not a legal holiday, and if a legal holiday, then on the next succeeding business day, at the time designated in the call, for the election of Directors, and the transaction of such other business as may come before it. (As amended April 2, 1946) Section 2. Special meetings of the stockholders may be called by the Board of Directors, the President or the Secretary upon written request of stockholders holding not less than one-tenth of all the shares entitled to vote at the meeting. In case an annual meeting shall be omitted through inadvertence or otherwise, the business of such meeting may be transacted at a special meeting duly called for the purpose. (As amended May 2, 1972) Section 3. Written or printed notice stating the place, day and hour of the meeting and, in case of a special meeting, the purpose or purposes for which the meeting is called, shall be delivered not less than 10 nor more than 60 days before the date of the meeting, either personally or by mail, by or at the direction of the President or the Secretary, to each registered holder entitled to vote at such meeting. If mailed, such notice shall be deemed to be delivered when deposited in the United States mail addressed to the registered holder at the address as it appears on the stock transfer books of the Company, with postage on it prepaid. (As amended May 2, 1972 and August 7, 1995) Section 4. Unless otherwise provided in the Articles of Association, a majority of the shares entitled to vote, represented in person or by proxy, shall constitute a quorum at a meeting of stockholders. If a quorum is present, the affirmative vote of the majority of the shares represented at the meeting and entitled to vote on the subject matter shall be the act of the stockholders, unless the vote of a greater number or voting by classes is required by law, by these By-Laws or by the Articles of Association. A majority vote of whatever stock shall be represented, even if less than a quorum, shall be sufficient (a) to adjourn from time to time until a quorum is present or (b) to adjourn sine die. (As amended May 2, 1972) Section 5. At all stockholders' meetings, holders of record of stock then having voting power shall be entitled to one vote for each share of stock held by them, respectively, upon any question or at any election, and such vote may, in all cases, be given by proxy, duly authorized in writing. But no proxy dated more than eleven months before the meeting, which shall be named therein, shall be accepted; and no proxy shall be valid after the final adjournment of such meeting. (As amended May 1, 1973 and August 7, 1995) Article V. Directors Section 1. The property and business of the Corporation shall be managed by a Board of Directors, each of whom must be a stockholder. The Directors shall be elected by ballot by majority vote of the stockholders present in person or represented by proxy at the election and entitled to vote on the question, except as otherwise provided in the Articles of Association or in these By-Laws. (As amended October 16, 1944; May 7, 1963 and February 17, 1987) No person shall be eligible for election or re-election as a Director after his/her seventieth birthday, provided that any Director whose term of office extends beyond his/her seventieth birthday shall be entitled to serve the remainder of the full term of the class of Directors to which he/she was elected. (As amended June 13, 1983 and November 2, 1987) A majority of the Directors shall at all times be persons who are not employees of the Corporation. The provisions of this paragraph shall not apply to the election of Directors by the holders of preferred stock when, in accordance with the Articles of Association, they shall be entitled to elect the smallest number of Directors necessary to constitute a majority of the full Board of Directors. (As amended April 6, 1953 and August 7, 1995) Section 2. Subject to the provisions of Section 5 below, the Board of Directors shall consist of not less than 9 nor more than 21 persons, the exact number to be fixed from time to time by resolution of the Board of Directors. Such exact number may be increased or decreased by the affirmative vote of the holders of at least 80 percent of the combined voting power of the then- outstanding shares of common stock and of any other class of stock then being expressly entitled to vote with the common stock on the question. The Directors shall be classified, with respect to the time for which they severally hold office, into three classes, as nearly equal in number as possible. Upon their initial election, the members of the first class shall hold office for a term expiring at the next annual meeting of stockholders after their election, the members of the second class shall hold office for a term expiring at the second annual meeting of stockholders after their election, and the members of the third class shall hold office for a term expiring at the third annual meeting of stockholders after their election. (As amended February 17, 1987) Section 3. Subject to the provisions of Section 5 below, any vacancies in the Board of Directors resulting from death, resignation, retirement, disqualification, removal from office or other cause may be filled only by a majority vote of the Directors then in office, though less than a quorum of the Board of Directors. Any Director elected in accordance with this provision shall hold office for the remainder of the full term of the class of Directors in which the vacancy occurred and until such Director's successor shall have been elected and qualified. No decrease in the number of authorized Directors constituting the entire Board of Directors shall shorten the term of any incumbent Director. (As amended February 17, 1987) Section 4. Except as otherwise provided in paragraph (e) of subdivision 6 of the Articles of Association, a Director may be removed from office only for cause and only by the affirmative vote of the holders of at least 80 percent of the combined voting power of the then-outstanding shares of common stock and of any other class of stock then being expressly entitled to vote with the common stock on the question. (As amended February 17, 1987) Section 5. Nothing contained in Sections 2 through 4 of this Article V shall be deemed to alter, amend or repeal the provisions of paragraph (b) of subdivision 6, paragraph (b) of subdivision 10F, or paragraph (a) of subdivision 20F, of the Articles of Association each of which confers, under the circumstances described therein, on the holders of the classes of stock referred to therein, the right to vote in the election of Directors. During any period in which such rights may be exercised, the provision or provisions conferring such rights shall prevail over any provision of these By-Laws inconsistent therewith. (As amended February 17, 1987) Section 6. Notwithstanding any other provision of these By-Laws, of the Articles of Association or of law, the affirmative vote of the holders of at least 80 percent of the combined voting power of the then-outstanding shares of common stock and of any other class of stock then being expressly entitled to vote with the common stock in the election of Directors shall be required to alter, amend or repeal Sections 2, 3, 4, 5 or 6 of this Article V. (As amended February 17, 1987) Section 7. The Board of Directors may hold its meetings and may have one or more offices, and may keep the books of the Corporation (except such records and books as by laws of Vermont are required to be kept within the State) within or outside of Vermont, at such places as it may from time to time determine. In addition to the powers and authorities by these By-Laws expressly conferred upon them, the Board of Directors may exercise all such powers of the Corporation, and do all such lawful acts and things as are not by law, by the Articles of Association or by these By-Laws required to be exercised or done by the incorporators or stockholders. Section 8. (Section 8 deleted in its entirety by amendment dated August 7, 1995) ARTICLE VI. Meetings of the Board Section 1. Regular meetings of the Board of Directors shall be held at such place and time as may be designated from time to time by the Board; and such meetings, and a regular meeting immediately following and at the same place as each annual meeting of the stockholders, may be held without notice. Special meetings of the Board of Directors may be called by the President, or by any two Directors, upon two days' notice to each Director, either personally or by mail or by telegram; and they may be held at any time without call or formal notice, provided all the Directors are present or waive notice thereof in writing. (As amended May 1, 1962) Section 2. A majority of the number of Directors fixed in accordance with the By-Laws shall constitute a quorum for the transaction of business, unless a greater number is required by the Articles of Association. The act of the majority of the Directors present at a meeting at which a quorum is present shall be the act of the Board of Directors, unless the act of a greater number is required by the Articles of Association. (As amended May 2, 1972) Section 3. Directors who are not also officers or regular employees of the Company may receive compensation for their services as such or as a member of any committee of the Board of Directors, as well as fixed sums and expenses for attendance at Directors' or committee meetings, in such amounts as may be provided from time to time by the Board of Directors, provided that nothing herein contained shall be construed to preclude any Director from serving the Company in any other capacity and receiving compensation therefor. (As amended May 5, 1981) Section 4. Directors and members of the Executive Committee and any other committee designated by the Board of Directors may participate in a meeting of such Board or committee by means of a conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and participation in a meeting in such a manner shall constitute presence in person at such meeting. (As amended May 3, 1977) ARTICLE VII. Officers Section 1. In each year there shall be elected by the Board of Directors, and if practicable, at its first meeting after the annual election of Directors, a President, one or more Vice Presidents, a Secretary, a Treasurer, and a Controller; and the Board may provide for and elect a Chairperson, one or more Assistant Secretaries, one or more Assistant Treasurers, and such other officers and prescribe such duties for them as in its judgment may, from time to time, be required to conduct the business of the Company. One of said Vice Presidents may be designated Executive Vice President. Any two or more offices may be held by the same person, except the offices of President and Secretary. All officers shall hold their respective offices for the term of one year, and until their successors, willing to serve, shall have been elected and, in the case of the Secretary, qualified, unless sooner removed; but they, and any of them, may be removed from their respective offices at the pleasure of the Board. Vacancies arising in any office from any cause shall be filled by the Board of Directors; and the persons chosen to fill vacancies shall serve for the balance of the unexpired term and until their successors shall have been elected. (As amended May 1, 1962; May 7, 1963; May 5, 1964; May 2, 1972 and November 2, 1987) Section 2. A Chairperson elected pursuant to Section 1 of this Article VII shall advise with and make his/her counsel available to the other officers of the Company and shall have such other powers and duties as may at any time be prescribed by these By-Laws and by the Board of Directors. He/She shall, when present, preside at all meetings of the stockholders and of the Board of Directors and of the Executive Committee. (As amended May 5, 1964) The President shall be the Chief Executive Officer of the Company and, subject to the direction of the Board of Directors and of the Chairperson (if one is elected), shall supervise the administration of the business and affairs of the Company and shall have such other powers and duties as may at any time be prescribed by these By-Laws and by the Board of Directors. In the absence of the Chairperson (or if no such Chairperson is elected), the President shall, when present, preside at meetings of the stockholders and of the Board of Directors and of the Executive Committee. (As amended May 5, 1964 and November 2, 1987) The Chairperson and the President shall be members of the Executive Committee (if such Executive Committee is designated by the Board of Directors) and each of them, in his/her discretion, may attend any meeting of any committee of the Board, whether or not he/she is a member of such committee. (As amended May 5, 1964) Section 3. The President shall, subject to the control of the Board of Directors, have charge of the business and affairs of the Company, including the power to appoint and to remove and to discharge any and all agents and employees of the Company not elected or appointed directly by the Board of Directors, and such other powers and duties as may at any time be prescribed by these By-Laws and by the Board of Directors. (As amended May 5, 1964) Section 4. The Vice President or Vice Presidents, if there shall be more than one, shall have such powers and duties as may from time to time be prescribed by the Board of Directors or by the President, but any powers and duties prescribed by the President shall not be inconsistent with any theretofore prescribed by the Board of Directors. In case the President, from absence or any other cause, shall be unable at any time to attend to the duties of the office of President requiring attention, or in case of his/her death, resignation or removal from office, the powers and duties of the President shall, except as the Board of Directors may otherwise provide, temporarily devolve upon the Executive Vice President if one shall have been designated and is able to serve, or in case of the latter's inability, upon the Vice President designated by the Board of Directors and able to serve and shall be exercised by such Vice President as acting President during such inability of the President, or until the vacancy in the office of President shall be filled. In case of the absence, disability, death, resignation or removal from office of both the President and such Vice President, the Board of Directors shall elect one of its members to exercise the powers and duties of the President during such absence or disability, or until the vacancy in one of said offices shall be filled. (As amended May 1, 1951 and May 1, 1962) Section 5. The Secretary shall reside in the State of Vermont and shall have the duties prescribed by law and such other duties as the By-Laws or the Board of Directors may prescribe. (As amended May 2, 1972) Section 6. The Treasurer shall have charge of, and be responsible for the custody and, jointly with the Controller, the receipt and disbursement of the funds of the Corporation, and shall deposit its funds in the name of the Company, in such banks, trust companies, or safe deposit vaults as the Board of Directors may direct. The Treasurer shall have the custody of such books and papers as in the practical business operations of the Company shall naturally belong in the office or custody of the Treasurer, or as shall be placed in his/her custody by the Board of Directors, by the Executive Committee, or by the President. The Treasurer shall also have charge of the safekeeping of all stocks, bonds, mortgages, and other securities belonging to the Company, but such stocks, bonds, mortgages, and other securities shall be deposited for safekeeping in a safe deposit vault to be approved by the Board of Directors or the Executive Committee, in a box or boxes, access to which shall be had as may be provided by resolution of the Board of Directors or by the Executive Committee. The Treasurer shall have such other powers and duties as are commonly incident to the office of Treasurer, or as may be prescribed. The Treasurer may be required to give bond to the Company for the faithful discharge of duties in such form and to such amount and with such sureties as shall be determined by the Board of Directors. (As amended November 2, 1987) Section 7. The Controller shall have charge of, and be responsible for the collection, and jointly with the Treasurer, the receipt and disbursement of the funds of the Corporation. The Controller shall maintain adequate records of all assets, liabilities, and transactions of the Company; shall see that adequate audits thereof are currently and regularly made and, in conjunction with other officers and department heads, shall initiate and enforce methods and procedures whereby the business of the Company shall be conducted with maximum safety, efficiency and economy. The Controller shall have the custody of such books, receipted vouchers, and other books and papers as in the practical business operations of the Company shall naturally belong in the office or the custody of the Controller, or as shall be placed in his/her custody by the Board of Directors, by the Executive Committee, or by the President. The Controller shall have such other powers and duties as are commonly incidental to the office of Controller, or as may be prescribed. The Controller may be required to give bond to the Company for the faithful discharge of duties in such form and to such amount and with such sureties as shall be determined by the Board of Directors. (As amended November 2, 1987) Section 8. Assistant Secretaries or Treasurers, when elected, shall assist the Secretary or Treasurer, as the case may be, in the performance of the respective duties assigned to such principal officers; and the powers and duties of any such principal officer, shall, except as otherwise ordered by the Board of Directors, temporarily devolve upon his/her assistant in case of the absence, disability, death, resignation or removal from office of such principal officer. They shall perform such other duties as may be assigned to them from time to time. (As amended May 7, 1963) ARTICLE VIII. Executive Committee Section 1. The Board of Directors may, by resolution passed by a majority of the Board, designate from their number an Executive Committee of such number, not less than three, as the Board may fix from time to time. The Executive Committee may make its own rules of procedure and shall meet where and as provided by such rules, or by resolution of the Board of Directors. A majority of the members of the Committee shall constitute a quorum for the transaction of business. During the intervals between the meetings of the Board of Directors, the Executive Committee shall have all the powers of the Board in management of the business and affairs of the Company except as may otherwise be provided by law, including power to authorize the seal of the Company to be affixed to all papers which may require it, and, by majority vote of all its members, exercise any and all such powers in such manner as such Committee shall deem best for the interest of the Company, in all cases in which specific directions shall not have been given by the Board of Directors, and in which the vote of a quorum of the full Board of Directors is not required by law, the Articles of Association, or by these By-Laws. (As amended May 2, 1972) Section 2. The Executive Committee shall keep regular minutes of its proceedings and report the same to the Board of Directors when required. The Board of Directors shall have power to rescind any vote or resolution of the Executive Committee, but no such recision shall have retroactive effect. ARTICLE IX. Inspection of Books All records, accounts, and papers of the Corporation shall be open to the inspection of every stockholder at reasonable times and for legitimate purposes; and, subject to such rights of inspection as may be afforded the stockholders by law, the Directors may make such reasonable regulations relative to such inspection, and take such action to prevent an inspection of corporate books or papers for illegitimate purposes as may be consistent with law. ARTICLE X. (Article X deleted in its entirety by amendment dated August 5, 1996) ARTICLE XI (As amended May 3, 1994) INDEMNIFICATION OF DIRECTORS, OFFICERS AND EMPLOYEES Section 1. Permissive Indemnification. To the extent legally permissible, the Company may indemnify any of its Directors, officers and employees who, as a result of such position, was or is a party or is threatened to be made a party to any contemplated, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative and whether formal or informal against expenses, actually and reasonably incurred by him or her in connection with such action, suit or proceeding. The term Expenses, as used in this Article, includes reasonable attorney's fees, damages, judgments, fines, amounts paid in settlement and costs including the costs of investigation and defense. Such indemnification against Expenses shall be payable only if (a) the Director, officer or employee acted in good faith, (b) the Director reasonably believed: (A) in the case of conduct in the Director's official capacity with the Company, that the Director's conduct was in its best interests; and (B) in all other cases, that the Director's conduct was at least not opposed to its best interests; and (c) with respect to any proceeding brought by a governmental entity, the Director had no reasonable cause to believe his or her conduct was unlawful, and the Director is not finally found to have engaged in a reckless or intentional unlawful act. Notwithstanding the foregoing and except as otherwise provided by law, the Company may not indemnify any Director, officer, or employee for any Expenses in any action by or in right of the Company in which such individual is adjudged liable to the Company. Any indemnification under this section (unless ordered by a court) shall be made by the Company only upon a determination that indemnification of the Director, officer or employee is proper because he or she has acted in good faith in conformance with the applicable standard of conduct as set forth herein. Such determination shall be made (a) by the Board of Directors by a majority vote of a quorum consisting of Directors who are not parties to such action, suit or proceeding or (b) if such a quorum is not obtainable, by majority vote of a committee duly designated by the Board of Directors (in which designation Directors who are parties to the action, suit or proceeding may participate), consisting solely of two or more Directors not at the time parties to the action, suit or proceeding; (c) by written opinion of special legal counsel: (A) selected by the Board of Directors or its committee in the manner prescribed in clause (a) or (b); or (B) if a quorum of the Board of Directors cannot be obtained under clause (a) and a committee cannot be designated under clause (b), selected by majority vote of the full Board of Directors (in which selection Directors who are parties to the action, suit or proceeding may participate); or (d) by the shareholders, but shares owned by or voted under the control of Directors who are at the time parties to the action, suit or proceeding may not be voted on the determination. Authorization of indemnification and evaluation as to reasonableness of Expenses shall be made in the same manner provided above as the determination that indemnification is permissible, except that if the determination is made by special legal counsel, authorization of indemnification and evaluation as to reasonableness of Expenses shall be made by those entitled under clause (c) above to select such counsel. The termination of any action, suit or proceeding by judgment, order, settlement, conviction, or upon a plea no nolo contendere or its equivalent, shall not of itself create a presumption that the person did not act in good faith in conformance with the applicable standard of conduct as set forth above. Section 2. Mandatory Indemnification. To the extent that a Director, officer or employee of the Company has been wholly successful on the merits or otherwise in defense of any action, suit, proceeding, claim, issue, or matter referred to in Section 1 of this Article, he or she shall be indemnified to the extent legally permissible against Expenses reasonably incurred by him or her in connection therewith. Section 3. Right To Rely On Corporate Information. In discharging his or her duty, any Director, when acting in good faith in conformance with the applicable standard of conduct as set forth above, may rely upon information, opinions, reports, or statements, including financial statements and other financial data, if prepared or presented by: (a) one or more officers or employees of the Company whom the Director reasonably believes to be reliable and competent in the matters presented; (b) legal counsel, public accountants, or other persons as to matters the Director reasonably believes are within the person's professional or expert competence; or (c) a committee of the Board of Directors of which the Director is not a member if the Director reasonably believes the committee merits confidence. Section 4. Advance Payment of Expenses. Expenses incurred by a Director, officer or employee in connection with any of the matters with respect to which indemnification may be sought pursuant hereto may be paid from time to time by the Company in advance of the final disposition of any such matter if the following conditions are met: (a) the Director furnishes the Company written affirmation of his or her good faith belief that he or she has met the standard of conduct described in Section 1 of this Article; (b) the Director furnishes the Company a written undertaking, executed personally or on the Director's behalf, to repay the advance if it is ultimately determined that the Director did not meet the standard of conduct; and (c) a determination is made that the facts then known to those making the determination would not preclude indemnification under this subchapter. Determinations and authorizations of payments under this Section 4 shall be made in the manner specified in Section 1 of this Article. The Board of Directors may authorize counsel (which may be either Company counsel or outside counsel) to represent such individual in any action, suit or proceeding, whether or not the Company is a party to such action, suit or proceeding. Section 5. Procedure For Indemnification. Subject to compliance with any applicable procedures in Sections 1 or 4, as the case may be, any indemnification of a Director, officer or employee of the Company or advance of Expenses to such an individual under the terms of this Article shall be made promptly. If the Company unreasonably denies a written request for indemnity or the advance payment of Expenses, either in whole or in part, or if payment in full pursuant to such request is not made promptly, the right to indemnification or advances as granted by this Article shall be enforceable by such individual in any court of competent jurisdiction. Such individual's costs and expenses including reasonable attorney's fees incurred in connection with successfully establishing his or her right to indemnification in any such action shall also be indemnified by the Company. Section 6. Non-Exclusivity of Indemnification Rights. The right of indemnification hereby provided shall not be deemed exclusive of or otherwise affect any other rights to which any individual seeking indemnification may be entitled by law, or under any agreement, vote of stockholders or otherwise, both as to action in his or her official capacity and as to action in another capacity while holding such office, and shall continue as to a person who has ceased to be a Director, officer or employee and shall inure to the benefit of the heirs, executors and administrators of such a person. Section 7. Other Organizations. The indemnification provisions of this Article shall extend to any Director, officer or employee who serves at the Company's request as director, officer or trustee of another organization, including, without limitation, an employee benefit plan, in which the Company has or had an interest as a stockholder, creditor, sponsor or otherwise. The right to rely on corporate information conferred in Section 3 of this Article shall also extend to the records, books of accounts and reports of any such other organization of which the individual serves as director, officer or trustee. Section 8. Survival. The foregoing indemnification provisions shall be deemed to be a contract between the Company and each individual who serves in any capacity as a Director, officer or employee of the Company at any time while these provisions are in effect. Except as may otherwise be required as a result of changes in the law governing indemnification of officers, directors and employees of Vermont corporations, any repeal or modification of the foregoing provisions shall not affect any right or obligation then existing and such "contract rights" may not be modified retroactively without the consent of such Director, officer or employee. ARTICLE XII. (As amended May 3, 1988) Miscellaneous Section 1. The funds of the Company shall be deposited to its credit in such banks or trust companies as the Board of Directors may, from time to time, designate, and shall be drawn out only for the purposes of the Company and only upon checks or drafts signed in such manner as shall be authorized by the Board of Directors in accordance with the power vested in them by these By-Laws. Section 2. No debts shall be contracted, except for current expenses, unless authorized by the Board of Directors or the Executive Committee. Section 3. All dividends shall be payable at such time as may be fixed by the Board of Directors. Before payment of any dividend or making any distribution of profits, there shall be set aside, out of the surplus or net profits of the Corporation such sum or sums as the Board of Directors, from time to time, in their absolute discretion, think proper as a reserve fund to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for such other purpose as the Board of Directors think conducive to the interest of the Corporation. Section 4. The first fiscal year of the Corporation shall be the period commencing September 1, 1929 and ending December 31, 1930, and thereafter each calendar year, commencing with the year 1931, shall be the fiscal year of the Corporation. ARTICLE XIII AMENDMENT Except as set forth in subdivision 21 of the Company's Articles of Association and in Article V of these By-Laws, these By-Laws may be altered, amended or repealed at any annual or special meeting of the stockholders called for the purpose, of which the notice shall specify the subject matter of the proposed alteration, amendment or repeal or the sections to be affected thereby, by vote of the stockholders, or if there shall be two or more classes or series of stock entitled to vote on the question, by vote of each such class or series. These By-Laws may also be altered, amended or repealed by vote of the majority of the number of Directors fixed in accordance with the By-Laws at a meeting called for that purpose of which the notice shall specify the subject matter of the proposed alteration, amendment or repeal or the sections to be affected thereby, except that the Directors shall not take any action which provides for indemnification of Directors or affects the powers of Directors or officers to contract with the Company, nor any action to amend this Article XIII, Sections 2, 3, 4, 5 or 6 of Article V, and except that the Directors shall not take any action unless permitted by law. Except as set forth in subdivision 21 of the Company's Articles of Association and in Article V of these By-Laws, any By-Law so altered, amended or repealed by the Directors may be further altered or amended or reinstated by the stockholder in the above manner. (As amended May 6, 1986, May 3, 1988 and August 5, 1996) EX-10 3 EXHIBIT 10.56.4 10.56.4 - - ------- FOURTH AMENDMENT TO 1985 OPTION AGREEMENT This Agreement, made and entered into as of December 31, 1996, by and between Vermont Electric Power Company, Inc., a Vermont corporation ("VELCO"), Central Vermont Public Service Corporation, a Vermont Corporation, ("Central Vermont"), Green Mountain Power Corporation, a Vermont corporation ("Green Mountain"), and Citizens Utilities Company, a Delaware corporation ("Citizens"); Central Vermont, Green Mountain and Citizens being also referred to herein individually as "Company" and collectively as Companies." WITNESS THAT: WHEREAS, each of the Companies is an original stockholder of VELCO, and each contributed certain assets to VELCO at the time of its incorporation; and WHEREAS, VELCO and the Companies were parties to a certain Agreement, dated March 29, 1957 (the "Four Party Agreement"), that included, among other things, purchase options relating to certain properties of VELCO that were subsequently more specifically described in an Agreement dated January 16, 1961, among said Companies and VELCO (the "1961 Agreement"), which options were extended to December 27, 1985; and WHEREAS, VELCO and the Companies are parties to a certain Agreement, dated December 27, 1985 ("the 1985 Option Agreement"), that extended the aforementioned purchase options to December 31, 1988; and WHEREAS, VELCO and the Companies were also parties to certain amendments to the 1985 Option Agreement that extended the aforementioned purchase options to December 31, 1996; and WHEREAS, the Companies desire to extend the aforesaid purchase options further on terms that are consistent with the terms and conditions of the Indenture of Mortgage, dated as of September 1, 1967, between VELCO and Bankers Trust Company, as Trustee, as now or hereafter amended or supplemented: NOW, THEREFORE, the parties to this Agreement hereby agree that the 1985 Option Agreement is amended as follows: 1. The third recital clause of said 1985 Option Agreement, as amended, is amended further by deleting therefrom the clause, "until a date no later than December 31, 1996,". 2. The first paragraph of SECTION 1 of said 1985 Option Agreement, as amended, is further amended by deleting therefrom the words, "December 31, 1996" and by substituting therefor the words, "the last date by which notice of intent to exercise such option must be given as provided herein". 3. The first paragraph of SECTION 1 of said 1985 Option Agreement, as amended, is further amended by inserting therein, immediately preceding the words, "the options of the other Companies shall expire 90 days thereafter", the words, ", not-withstanding any other provision herein,". 4. The second paragraph of SECTION 1 of said 1985 Option Agreement, as amended, is further amended by deleting therefrom the words, "October 1, 1996", and by substituting therefore the words, "October 1, 2001, provided that, if any party shall have given notice, pursuant to the provisions of SECTION 7 that it does not wish to renew the Agreement, then on or before November 1 of the year in which the Agreement is to terminate". 5. SECTION 7 of said 1985 Option Agreement, as amended, is deleted, and the following is substituted in lieu thereof: "SECTION 7. This Agreement shall continue in full force and effect until December 31, 1998, provided, that it shall be automatically renewed thereafter for three additional terms of one year each, unless, prior to October 1 of any year in which it would otherwise terminate, one of the parties to which the Agreement grants an option gives notice to all of the other such parties that it does not wish to renew the Agreement, in which case, the Agreement shall terminate on the December 31 next following the giving of such notice." This Agreement may be executed in counterpart copies which shall be combined and treated as one original. IN WITNESS WHEREOF, the parties hereto have each caused this Agreement to be executed on its behalf by a duly authorized officer. CENTRAL VERMONT PUBLIC SERVICE CORPORATION Attest: By: /s/ Joseph M. Kraus /s/ Mary C. Marzec Its CITIZENS UTILITIES COMPANY Attest: By: /s/ John J. Lass /s/ Kevin Perry Its GREEN MOUNTAIN POWER CORPORATION Attest: By: /s/ Edward M. Norse /s/ Bonnie O'Rourke Its VERMONT ELECTRIC POWER COMPANY, INC. Attest: By: /s/ Thomas Wies /s/ Joyce A. Norris Its Vice President EX-10 4 EXHIBIT 10.82 10.82 - - ------ CENTRAL VERMONT PUBLIC SERVICE CORPORATION MANAGEMENT INCENTIVE PLAN Adopted As Of January 1, 1997 I. PURPOSE The Company's executive officers participate in the core utility Management Incentive Plan (the "Incentive Plan"). The purpose of the Incentive Plan is to focus the efforts of the executive team on the achievement of challenging and demanding corporate objectives. When corporate performance attains the specified annual performance objectives, an award is granted. A well-directed incentive plan, in conjunction with competitive salaries, provides a level of compensation which fully rewards the skills and efforts of the executives. II. ADMINISTRATION The Incentive Plan will be administered by the Compensation Committee of the Board of Directors (the "Committee"). All Committee actions will be subject to review and approval by the full Board of Directors (the "Board"). At the beginning of each year ("Plan Year"), the Committee will submit to the Board its recommendations for that Plan Year as to (i) the Incentive Plan's Corporate Performance Goals, and (ii) the eligible participants. After the end of each Plan Year, the Committee will report to the Board with respect to achievement of the approved Corporate Performance Goals and individual performance measures for that Plan Year, and will submit to the Board its recommendations as to the appropriate award payment levels for each eligible participant. Recommendations of the Committee, with such modifications as may be made by the Board, will be binding on all participants in the Incentive Plan. III. THE PLAN There is established a financial performance threshold, below which no incentive awards will be paid. The threshold is calibrated against the allowed return on equity. The degree to which the allowed return on equity is achieved generates a pool which is available to fund incentive payouts. The pool funds awards, but performance measures must also be met in the following areas to receive an award. Each measure is equally weighted. Return on equity. While this measure is used to establish the incentive pool, it is also one of the measures which is assessed in determining distribution of the pool. Customer satisfaction. Measures the degree of satisfaction of customers who have had a recent service interaction. The measurement is conducted by an external firm. Individual performance. Based on advice and recommendation from the Chief Executive Officer for those reporting to him. The Committee evaluates the Chief Executive Officer's performance. If the maximum payout on all of the standards were to be achieved, the total award would represent 30% of base salary for the Chief Executive Officer, 25% of base salary for the Chief Operating Officer, 20% for Senior Vice Presidents and Vice Presidents, and 15% for other designated officers. IV. Any annual incentive award will consist of cash (50%) and Central Vermont Public Service Corporation stock (50%) which will have a three year vesting restriction. Applicable dividends will be paid on awarded restricted stock prior to vesting. The Board may choose to make awards of non-qualified stock options to designated officers consistent with Plan design and intent. V. AMENDMENTS The Board reserves the right to amend, modify or terminate the Incentive Plan at any time. EX-21 5 EXHIBIT 21.1 EXHIBIT 21.1 ----------------- Subsidiaries of the Registrant ---------------------------------- State in Which Incorporated --------------- Connecticut Valley Electric Company Inc. (a) (F1) New Hampshire Vermont Electric Power Company, Inc. (b) (F2) Vermont C.V. Realty, Inc. (a) (F1) Vermont Central Vermont Public Service Corporation - Bradford Hydroelectric, Inc. (a) (F1) Vermont Central Vermont Public Service Corporation - East Barnet Hydroelectric, Inc. (a) (F1) Vermont CV Energy Resources, Inc. (a) (F1) Vermont Catamount Rumford, Inc. (a) (F1) Vermont Equinox Vermont Corporation (a) (F1) Vermont Appomattox Vermont Corporation (a) (F1) Vermont Catamount Energy Corporation (a) (F1) Vermont Catamount Williams Lake, Ltd. (a) (F1) Vermont Catamount Glenns Ferry Corporation Vermont Catamount Rupert Corporation Vermont Summersville Hydro Corporation Vermont Gauley River Management Corporation Vermont SmartEnergy Services, Inc. (a) (F1) Vermont - - - - - - - - - - - - - - - - - - - - - - - - - - - - (FN) (F1) (a) Included in consolidated financial statements (F2) (b) Separate financial statements do not need to be filed under Regulation S-X, Rule 1-02 (v) defining a "significant subsidiary", and Rule 3-09, which sets forth the requirement for filing separate financial statements of subsidiaries not consolidated. EX-23 6 EXHIBIT 23.1 EXHIBIT 23.1 ------------ CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS ----------------------------------------- As independent public accountants, we hereby consent to the incorporation of our reports dated February 3, 1997 included in this Form 10-K, into Central Vermont Public Service Corporation's previously filed Registration Statements on Form S-8, File No. 33-22741, Form S-8, File No. 33-22742, Form S-8, File No. 33-58102, Form S-8, File No. 33-62100, and Form S-3, File No. 33-39691. ARTHUR ANDERSEN LLP Boston, Massachusetts March 25, 1997 EX-27 7 FINANCIAL DATA SCHEDULE EXHIBIT 27
UT This Financial Data Schedule contains summary financial information extracted from the Consolidated Financial Statements included herein and is qualified in its entirety by reference to such financial statements (dollars in thousands, except per share amounts). 1,000 YEAR DEC-31-1996 DEC-31-1996 PER-BOOK 324,941 58,951 55,502 63,574 0 502,968 67,059 45,273 74,137 186,469 20,000 8,054 117,374 5,750 0 0 3,015 0 18,304 1,094 142,908 502,968 290,801 10,216 257,310 267,526 23,275 6,092 29,367 9,925 19,442 2,028 17,414 9,699 8,136 42,688 1.51 0
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