-----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, UMkbPgPxciCr3c6TzD829H/UG/8S1Ew99TtlPGYFPtThn4jbE2fKU/c/BYdzJxV1 NrFa3YZcEN2ynRwKHMpXXw== 0000018808-00-000004.txt : 20000531 0000018808-00-000004.hdr.sgml : 20000531 ACCESSION NUMBER: 0000018808-00-000004 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000310 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: SEC FILE NUMBER: 001-08222 FILM NUMBER: 566047 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 12/31/99 UNITED STATES 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, 1999 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 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 (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 incorporated by reference in Part III of this Form 10-K 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: $126,134,855 based upon the closing price as of January 31, 2000 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, 2000, there were outstanding 11,466,805 shares of Common Stock, $6 Par Value. DOCUMENTS INCORPORATED BY REFERENCE The Company's Definitive Proxy Statement relating to its Annual Meeting of Stockholders to be held on May 2, 2000 to be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Act of 1934, is incorporated by reference in Items 10, 11, 12, and 13 of Part III of this Form 10-K. Cover page continued Form 10-K - 1999 TABLE OF CONTENTS Page PART I Item 1. Business................................................ 2 Item 2. Properties.............................................. 22 Item 3. Legal Proceedings....................................... 23 Item 4. Submission of Matters to a Vote of Security Holders..... 24 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.................................... 24 Item 6. Selected Financial Data................................. 25 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................... 26 Item 8. Financial Statements and Supplementary Data............. 56 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................... 90 PART III Item 10. Directors and Executive Officers of the Registrant...... 90 Item 11. Executive Compensation.................................. 90 Item 12. Security Ownership of Certain Beneficial Owners and Management............................................. 90 Item 13. Certain Relationships and Related Transactions.......... 91 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K............................................ 91 Signatures........................................................ 114 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 140,866 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 61% of total mWh sales excluding mWh sales related to the Virginia Power Alliance (2,986,682 mWh) for the year 1999. Sales to the five largest retail customers receiving electric service from the Company during the same period aggregated about 5% of the Company's total electric revenues for the year. The Company's requirements resale sales accounted for approximately 4%, entitlement sales accounted for 10% and other resale sales which include contract sales, opportunity sales, sales to NEPOOL and short-term system capacity sales accounted for approximately 25% of total mWh sales for the year 1999. 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 10,427 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 1999. Sales to its five largest retail customers during the same period aggregated about 17% of Connecticut Valley's total electric revenues for the year 1999. 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 the Province of 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 one wholly owned subsidiary created for the purpose of financing and constructing a hydroelectric facility in Vermont. This hydroelectric facility, owned by Central Vermont Public Service Corporation - East Barnet Hydroelectric, Inc. became operational September 1, 1984 and has been leased and operated by the Company since its in-service date. In addition, the Company has a wholly owned non-utility subsidiary, Catamount Resources Corporation, which was formed for the purpose of holding the Company's subsidiaries that invest in unregulated business opportunities. For additional information of the Company's unregulated activities, see PART II, Item 8 herein. For Financial Information About Segments for the last three fiscal years, See Part II, Item 8, Note 16-Segment Reporting. 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 Unit #3 ("Unit #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 Part II Item 7 herein and refer to Part II, 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 Part II Item 8 herein for disclosures relating to the shut down of the Maine Yankee, Connecticut Yankee and Yankee Atomic Nuclear Power plants. 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 described below. 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(c) 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 a Department retail sales request, 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. Such sales have not been made in the Company's service area since 1993. 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 the summer of 1997, the City of Claremont ("Claremont"), New Hampshire engaged a consulting firm to conduct a study to determine Claremont's options under New Hampshire law including the possible municipalization of Connecticut Valley's service area located within its jurisdiction. The City Council ("Council") appropriated approximately $75,000 for purposes of the study which has been completed. In May 1999, the City Council of Claremont considered whether to publicly warn a vote to acquire the Company's facilities located in Claremont and to establish a municipal electric utility pursuant to N.H.R.S.A. Chapter 38 et. sec. By vote of six to three, the Council voted to proceed towards the establishment of a municipal electric utility and acquisition of Company facilities. This action required that Claremont hold an election within one year of the Council's action to determine if a majority of the qualified voters will confirm the Council's decision. Should the Council's decision be confirmed by Claremont voters, the Council will have thirty days from the date of the confirming vote to notify the Company of its intention to purchase all or such portion of the Company's plant and property located within Claremont and such portion of the plant lying within the municipality as the public interest may require. The company would thereafter have sixty days to reply to the Claremont's inquiry. If there is no agreement between the Company and Claremont, Claremont may proceed to condemn the Company's facilities with proceedings before the NHPUC as provided for in Chapter 38 and the FERC as provided for in its Rule 35.26 (18CFR Chapter 1). On September 8, 1999, the City Council voted to postpone indefinitely the citizens' vote on municipalization which had been set for November 2, 1999. A group of Claremont citizens opposed to a government electric takeover actively participated in the November 2, 1999 municipal election, resulting in the election of three challengers opposed to the idea, and the creation of a majority on the city council against the municipalization of Connecticut Valley's system. The Company cannot predict at this time when or if a citizens' vote on municipalization will be held in connection with this initiative. 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 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 New Hampshire Supreme Court in favor of PSNH's position. The New Hampshire Supreme Court upheld the NHPUC's position, but did not rule on just compensation issues. The NHPUC ordered the petitioner to seek a ruling from the FERC that its proposed operations were not a "sham transaction." The petitioner failed to seek such a ruling, therefore, the NHPUC closed this docket. For a discussion relating to Electric Industry Restructuring in Vermont and New Hampshire see PART II, Item 7 herein. For a discussion relating to the Company's wholesale electric business see Wholesale Rates below. RATE DEVELOPMENTS Vermont Retail Rates. On September 22, 1997, the Company filed for a 6.6% or $15.4 million per annum, general rate increase to become effective June 6, 1998 (Docket No. 6018). Action on this case is stayed pending an interlocutory appeal to the Vermont Supreme Court ("VSC"). Also on September 22, 1997, the Company filed a retail rate redesign whose primary purpose was to eliminate seasonal rates. The PSB has not yet acted on this request. On June 12, 1998, the Company filed with the PSB a request for a 10.7% retail rate increase ($24.9 million of annualized revenues) to become effective March 1, 1999 to cover primarily the higher power costs that the Company will incur under the Vermont Joint Owners ("VJO") contract with Hydro-Quebec. In this proceeding the PSB delayed the examination of the prudence and used-and-usefulness of the Hydro-Quebec Contract pending the VSC's decision in the appeal of Docket No. 6018. After extensive negotiation, on October 28, 1998 the DPS filed a Memorandum of Understanding ("MOU") between it and the Company which proposed a resolution of the issues other than power costs under the Hydro-Quebec Contract. The proposed resolution included, among other provisions, a final determination of the Company's rate request except for issues of prudence and used-and-usefulness of the Hydro-Quebec Contract, and a temporary, pro forma Hydro-Quebec prudence and used-and-usefulness disallowance modeled on the Hydro-Quebec disallowance which the PSB applied to Green Mountain Power Corporation in its February 1998 rate order. To reflect both the final and the temporary cost of service determinations, the MOU proposed a "temporary rate increase" of 4.7% or $10.9 million on an annualized basis effective with service rendered January 1, 1999. By order dated December 11, 1998, the PSB approved the MOU in its entirety. For additional information regarding rate increase requests see PART II, Item 7 "Rates and Regulation" and Item 8 "Retail Rates" herein. New Hampshire Retail Rates. Connecticut Valley's retail rate tariffs, approved by the NHPUC, contain a Fuel Adjustment Clause ("FAC") and a Purchased Power cost Adjustment ("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 1998 and reconciliations from 1997, the combined 1998 FAC and PPCA would have resulted in an increase in revenues of approximately $2.1 million for 1998. Based on a motion by Claremont, an intervenor, the NHPUC, in its order dated December 31, 1997, found that Connecticut Valley was imprudent not to have terminated its wholesale power contract with the Company and froze Connecticut Valley's FAC and PPCA rates. Subsequently, the NHPUC, in deference to a temporary restraining order issued by a federal district court, allowed FAC and PPCA rates effective May 1, 1998 that would make the Company whole for 1997 under collections, the 1998 under collections incurred through April 30, 1998, and the increase in 1998 power costs. On the basis of estimates of costs for 1999 and reconciliations from 1998, the combined 1999 FAC and PPCA rates would have resulted in a decrease in revenues of approximately $2.3 million for 1999. The decrease was primarily caused by the elimination of the various under collections from prior periods mentioned above. Claremont filed a motion to determine the prudence of the 1999 power costs. However, by agreement of the parties, including the NHPUC, the hearing was limited to the mathematical calculation of the FAC and PPCA. An NHPUC order allowed the decrease. Effective June 1, 1999, pursuant to an appeals court order related to the temporary restraining order issued by the federal district court, the NHPUC reduced Connecticut Valley's FAC and PPCA rates to the level in effect at December 31, 1997. Such level caused a $600,000 under collection of power costs for the subsequent seven-month period. On the basis of estimates of costs for 2000 and reconciliations from 1999, the combined 2000 FAC and PPCA rates would have resulted in an increase in revenues of approximately $1.9 million for 2000. The increase was primarily caused by the reduction of FAC and PPCA rates to the level in effect at December 31, 1997. In fact, had the NHPUC not ordered the reduction in rates to a level below cost of service effective June 1, 1999, Connecticut Valley would have filed for a 4.8% decrease. The NHPUC ordered the FAC and PPCA to remain unchanged at the level in effect at December 31, 1997. See PART II, Item 7 herein for additional information regarding New Hampshire Electric Industry Restructuring and Item 8 Note 13 herein for information regarding Retail Rates-New Hampshire. 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 Conservation and Load Management ("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. The C&LMPA further provides for the future recovery of shareholder incentives related to past C&LM activities. The NHPUC had approved the termination of C&LM activities by Connecticut Valley at the end of 1998. The NHPUC issued an order allowing an adequate level of recovery of lost revenues and administration C&LM costs for 2000. Connecticut Valley filed to eliminate seasonal rates and to implement non-seasonal rates because the wholesale power market rules had been revised in New England such that the disproportionate cost emphasis placed on a utility's annual peak had been eliminated. Higher winter rates during the time the Company would likely have experienced its annual peak had signaled this cost emphasis to retail customers. Pursuant to a stipulation signed by the NHPUC staff, the Office of the Consumer Advocate, and Claremont, the NHPUC allowed non-seasonal rates effective January 1, 2000. Connecticut Valley also purchases power from several Independent Power Producers ("IPPs"), who own qualifying facilities as defined by the Public Utility Regulatory Policies Act of 1978. In 1999, under long-term contracts with these qualifying facilities, Connecticut Valley purchased 40,145 mWh, of which 37,309 mWh were purchased from Wheelabrator Claremont Company, L.P., ("Wheelabrator") who owns a solid waste plant. Connecticut Valley had filed a complaint with FERC stating its concern that Wheelabrator has not been a qualifying facility since the plant began operation. On February 11, 1998, the FERC issued an Order denying Connecticut Valley's request of a refund of past purchased power costs and lower future costs. The Company filed a request for rehearing with the FERC on March 13, 1998 which was denied. Subsequently, Connecticut Valley appealed to the D.C. Circuit Court of Appeals which has yet to result in a decision. See PART II, Item 7 herein for detailed information regarding New Hampshire Electric Industry Restructuring. 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 $226,000 or 1.9% for 1999 power costs., (2) a reconciliation of 1998 revenues to actual costs which resulted in an additional billing of $253,000, including interest, and (3) a revenue decrease of $63,000 or 0.5% for 2000 power costs. An 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. On June 25, 1997, the Company filed with the FERC an application for recovery of stranded costs and a notice of cancellation of the rate schedule under which the Company sells firm power to Connecticut Valley contingent upon the recovery of stranded costs. The stranded cost obligation, expressed on a net present value basis as of January 1, 2000, is $44,925,000, would be authorized by the Company's open access Transmission Service Tariff No. 7, and collected as a surcharge to the transmission charges of any customer that uses the Company's transmission system to wheel power for ultimate delivery within Connecticut Valley's service area. The surcharge is expected to recover the stranded costs over a ten-year period. By order dated December 18, 1997, the FERC rejected the Company's filing on the grounds that the transmission tariff was an inappropriate vehicle for recovery. Pursuant to the FERC request in that order, the Company filed a letter stating its intention to refile the stranded cost recovery as an exit fee to the rate schedule under which the Company sells firm power to Connecticut Valley. The Company did so on January 12, 1998. The FERC accepted the filing and bifurcated the proceeding, first, to determine whether Connecticut Valley would become an unbundled transmission customer of the Company and, second, to determine the Company's expectation period for serving Connecticut Valley and the allowable amount of the exit fee. The Company filed a request with the FERC for an exit fee mechanism to collect stranded costs resulting from the cancellation of the contract with Connecticut Valley. The request described all of the ways Connecticut Valley will become an unbundled transmission customer of the Company subsequent to termination, and establishing the expected period of service based upon the date of termination, whenever that occurs, and the weighted average service life of its commitments to power resources to serve Connecticut Valley. The stranded cost obligation sought to be recovered through an exit fee expressed on a net present value basis as of January 1, 2000, is approximately $44,925,000. During April and May 1999, hearings were held at the FERC before the Administrative Law Judge ("ALJ") and a ruling of the ALJ is expected in the first half of 2000. It is expected that the FERC will act on the Judge's recommendations sometime thereafter. For additional information regarding legal and regulatory proceedings, see PART II, Item 7, Electric Industry Restructuring and Item 8, Note 13, Retail Rates. 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 VELCO 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 New Hampshire Electric Cooperative 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. The FERC has not taken action on the settlement. 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, which was approved by the FERC, embodied not only the open access principles set forth in the FERC pro forma transmission tariff, but also continued to embody the rate making and other Vermont and New England specific non-rate terms and conditions. The Company has made a number of filings to modify the Transmission Tariff in response to FERC orders related to transmission tariffs of other utilities and to update certain fixed charges and methodologies. All FERC orders received have approved such modifications. In 1997 the Company gave notice of termination effective December 31, 1999 to the seven customers taking transmission service under its Transmission Tariff NO. 3. The seven customers began taking service under the Transmission Tariff beginning January 1, 2000. POWER RESOURCES Overview. The Company's and Connecticut Valley's energy generation and purchased power required to serve their retail and firm wholesale customers was 2,559,051 mWh for the year ended December 31, 1999. The maximum one-hour integrated demand during that period was 420.5 mW, which occurred on December 28, 1999. The Company's and Connecticut Valley's total energy generation and purchased power in 1999, including that related to all resale customers, was 6,771,767 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, 1999. For additional information related to purchased power costs, refer to PART II, Item 7 herein.
Year Ended December 31, 1999 Net Effective Capability 12 Month Generated Average and Purchased mW mWh % WHOLLY-OWNED PLANTS: Hydro....................... 40.7 180,530 2.7 Diesel and Gas Turbine..... 28.9 2,063 - JOINTLY OWNED PLANTS: Millstone #3................ 19.7 143,227 2.1 Wyman #4.................... 11.0 32,785 0.5 McNeil...................... 10.5 43,750 0.6 EQUITY OWNERSHIP IN PLANTS: (Purchased) Vermont Yankee.............. 158.5 1,264,044 18.7 MAJOR LONG-TERM PURCHASES: Hydro-Quebec................ 172.3 1,329,609 19.6 OTHER PURCHASES: System and other purchases.. 469.1 413,785 6.1 Small power producers....... 34.2 193,114 2.9 Unit purchases.............. 6.7 8,376 0.1 Entitlement purchases....... 10,651 0.2 NEPEX......................... - 163,151 2.4 VIRGINIA POWER ALLIANCE 752.0 2,986,682 44.1 ------- --------- ----- TOTAL.................... 1,703.6 6,771,767 100.0 ======= ========= =====
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 1999 Fuel mW Generation Load Net Plant Name Location Type Ownership Entitlement mWh Factor Investment Millstone Unit #3 Waterford, Nuclear 1.73% 20 143,227 82% $49,900,626 Connecticut Wyman #4 Yarmouth, Oil 1.78% 11 32,785 34% $ 1,287,181 Maine Joseph C. McNeil Burlington, Various 20.00% 10.6 43,750 47% $ 7,303,506 Vermont Highgate Trans- Highgate Springs, 47.35% N/A N/A N/A $ 8,497,614 mission Facility Vermont
The Company receives its share of the output and capacity of Unit #3, an 1149 mW nuclear generating facility (see discussion below); Wyman #4, a 619 mW generating facility and Joseph C. McNeil, a 53 mW generating facility. The Highgate Convertor, a 225 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. The Company is responsible for its share of the operating expenses of these facilities. 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 3.9% of its entitlement. The Company's current equity ownership and net entitlement percentages are 31.3 and 31.1, 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 21, 2012. Vermont Yankee's net capability is 522 mW of which about 162.6 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) 1995......................... 86.3 84.8 1996......................... 84.5 82.8 1997......................... 95.4 93.3 1998......................... 75.2 73.5 1999......................... 90.9 88.8
Vermont Yankee was shut down for scheduled refueling outages in 1995, 1996, 1998 and 1999. As described in the overview section above, the Company is also 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) (See Note 4) Connecticut Yankee............ (See Note 4) (See Note 4) Yankee Atomic................. (See Note 4) (See Note 4)
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, including the potential sale of Vermont Yankee, refer to PART II, Item 8 herein. _______________ Notes: (1) Currently, the Company resells at cost, through VELCO, about 20 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) Maine Yankee, Connecticut Yankee and Yankee Atomic permanently ceased power operations of their Nuclear Power Plants. See Decommissioning Expense discussion below. Decommissioning Expense. Each of the Yankee companies 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. The Company's entitlement percentage of decommissioning costs for Vermont Yankee, Maine Yankee, Connecticut Yankee and Yankee Atomic 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 $73.4 Maine Yankee 1998 $343.9 $6.9 $3.6 Connecticut Yankee 1996 $426.7 $8.5 $3.6 Yankee Atomic 1994 $370.0 $13.0 $5.4
Vermont Yankee's current decommissioning cost study is based on a 1994 site study. The FERC approved settlement agreement allowed $312.7 million, in 1993 dollars, as the estimated decommissioning cost. Based on the study's assumed cost escalation rate of 5.4% per annum and an expiration of the Plant's operating license in the year 2012, the estimated current cost of decommissioning is $428.7 million and, at the end of 2012, is approximately $816.6 million. The present value of the pro rata portion of decommissioning costs recorded to date is $290.0 million of which the Company's share is $101.5 million. Under the FERC approved settlement agreement, Vermont Yankee was required to file with FERC an updated decommissioning cost study by April 1, 1999. On May 13, 1999, in light of the ongoing discussions involving the possible sale of the Vermont Yankee Nuclear Power plant, the FERC approved a settlement agreement extending the required filing date to April 1, 2000. On November 17, 1999, Vermont Yankee executed an Asset Purchase agreement with AmerGen Energy Co. The sale of the nuclear generating plant would transfer responsibility for decommissioning the plant to the new owner. The price to be paid by AmerGen for the plant and property will range from $10 million to $23.5 million depending on when the sale occurs. Additionally, Vermont Yankee's current owners will make a one-time payment of $54.3 million to pre-pay the plant's decommissioning fund at $312.7 million. In return AmerGen will assume full responsibility for all future operating costs and the estimated $816.6 million price tag for decommissioning the plant at the end of its operating license in 2012. The agreement is subject to several conditions, including approvals or specific rulings by various regulatory authorities. As such, execution of the agreement does not provide assurance that the sale will occur. This agreement will also involve the Company entering into a contract to purchase a portion of the power produced by this plant. During 1996, Vermont Yankee initiated a Design Basis Documentation project expected to be complete by December 31, 2001. This project was undertaken to incorporate all design documentation into a centralized system. The objective is to ensure that Vermont Yankee maintains its safety margins in connection with any plant modifications. The Design Basis Documentation project will create a set of design basis documents which will support more efficient systematic problem solving, maintenance, and system overview. This effort supports the safe, cost effective, long term operation of the Vermont Yankee Plant. Vermont Yankee received FERC approval in 1996 to defer these unrecovered study costs and amortize the costs through billings to Sponsors over the remaining license life of the Plant. The Company's 35% share of the total cost for this Project is expected to be between $5.5 million and $6.2 million. See Part II Items 7 and 8 for additional information. 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 and 2) a 1.7303% joint-ownership interest in Unit #3 of the Millstone Nuclear Power Station. The Company is responsible for paying its ownership percentage of decommissioning costs for Unit #3. Based on a 1997 study, the total estimated obligation at December 31, 1999 was approximately $619.5 million and the funded obligation was about $229.0 million. The Company's share for the total obligation and funded obligation was approximately $10.7 and $4.0 million, respectively. These costs are included in depreciation expenses. 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 information regarding the premature shutdown of the Maine Yankee, Connecticut Yankee and Yankee Atomic nuclear power plants. 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 and Northeast Utilities Service Co.'s efforts relating to Unit #3. On August 7, 1997, the Company and eight other non-operating owners of Unit #3 filed a demand for arbitration with Connecticut Light and Power Company and Western Massachusetts Electric Company, both NU affiliates, and lawsuits against NU and its trustees. The arbitration and lawsuits seek to recover costs associated with replacement power, operation and maintenance costs and other costs resulting from the lengthy outage of Unit #3. The non-operating owners claim that NU and two of its wholly owned subsidiaries failed to comply with NRC's regulations, failed to operate the facility in accordance with good operating practice and attempted to conceal their activities from the non-operating owners and the NRC. On September 15, 1999, NU announced that it intends to auction its nuclear generating plants, including Unit #3. We cannot predict at this time the effect of such an auction, if it occurs, on the Company or on the ongoing litigation. On October 27, 1999, NU and New England Power Company, ("NEP"), disclosed that NU had reached an agreement with NEP and Montaup Electric Company ("MEC"), two of the non-operating minority joint owners, to settle their claims in the arbitration and lawsuits. The settlement involves payment of fixed and contingent amounts to NEP and MEC and the inclusion of their Unit #3 interests in NU's auction of the plant. On January 28, 2000, Central Maine Power Company ("CMP") also one of the non-operating minority joint owners, disclosed that NU and CMP had reached an agreement to settle CMP's claims in the arbitration and litigation on terms similar to the NEP and MEC settlement. The other non-operating minority joint owners, including the Company, remain active in the arbitration and lawsuits and in seeking to settle our claims against NU. 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 1999 reload was approximately $21 million. Future refueling costs will depend on market and contract prices. On January 20, 1997, Vermont Yankee entered into an agreement with a former uranium supplier whereby the supplier could opt to terminate a production purchase agreement dated August 4, 1978. Although there had been no transactions under the production purchase agreement for several years, Vermont Yankee maintained certain financial rights. In consideration for the option to terminate the production purchase agreement and the subsequent exercise of the option, Vermont Yankee received $0.6 million in 1997 which was recorded as an offset to nuclear fuel expense. The potential future payments that Vermont Yankee could receive over a ten year period, range from $0.0 million to $1.6 million. No payments were received in either 1999 or 1998 by Vermont Yankee under this agreement. Due to the uncertainty of this transaction, the potential benefits will be recorded on a cash basis. 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 has not been met and is expected to be delayed significantly. It is not certain when the DOE will accept spent nuclear fuel and high-level radioactive waste from Vermont Yankee and other owners of nuclear power plants. These delays by the DOE have caused Vermont Yankee to consider other costly alternatives for storing high level waste. 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 one mill per kilowatt hour of nuclear generated and sold electricity after April 6, 1983. Although the $39.3 million for the one-time fee has been collected from the Sponsors in rates, 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 repository. Interest accrues on the unpaid obligation based on the thirteen-week Treasury Bill rate and is compounded quarterly. Through 1999, Vermont Yankee accumulated $101.5 million in an irrevocable trust to be used exclusively for defeasing this obligation ($108.8 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. In 1999, Vermont Yankee received an NRC license amendment allowing the installation of additional storage racks in the existing spent fuel pool. When installed, the additional storage racks will increase the capacity of the spent fuel to allow full core discharge capability through year 2008 refueling outage. Vermont Yankee is also investigating other options for additional storage capacity beyond the year 2001. In November 1997, the U.S. District Court of Appeals for the D.C. Circuit ruled that the lack of an interim storage facility does not excuse the DOE from meeting its contract obligation to begin accepting spent nuclear fuel no later than January 31, 1998. The ruling said, however, that the 1982 federal law could not require the DOE to accept waste when it did not have a suitable storage facility. The court directed the plaintiffs to pursue relief under terms of their contracts with the DOE. Based on this ruling, since the DOE did not take the spent nuclear fuel as scheduled, it may have to pay contract damages. In May 1998, the same court denied petitions from 60 states and state agencies and 41 utilities, including Vermont Yankee, asking the court to compel the DOE to submit a program, beginning immediately, for disposing of spent nuclear fuel. The petitions were filed after the DOE defaulted on its January 31, 1998 obligation to begin accepting the fuel. The court directed Vermont Yankee and other plaintiffs to pursue relief under the terms of their contracts with the DOE. In a petition filed in August 1998, the court's May 1998 decision was appealed to the U.S. Supreme Court. In November 1998, the Supreme Court declined to review the lower court ruling that said utilities should go to court and seek monetary damages from the DOE. Also, in November 1998, the U.S. Court of Federal Claims ruled that the DOE violated a commitment to remove spent nuclear fuel from civilian nuclear power plants. The claims court issued a ruling of summary judgment in favor of Yankee Atomic Power Co., which was the first of ten utilities to sue at the court a specialized body that hears only money disputes. The claims court is scheduling further proceedings to decide the amount of damages. The average energy and capacity costs to the Company of energy generated at the Vermont Yankee plant was 4.68, 4.78, 4.06, 5.81 and 5.14 cents per kWh for the years 1995 through 1999, 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 $9.7 billion. Beyond that a licensee is indemnified under the Price-Anderson Act, 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 $9.5 billion per incident by assessing $88.1 million against each of the 108 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 adjusted at least every five years to reflect inflationary changes. Currently the Company's interests in the nuclear power units are such that it could become liable for an aggregate of approximately $3.7 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 is purchasing varying amounts of power from Hydro-Quebec under the VJO contract through 2016. 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 average annual amount of capacity that the Company will purchase through October 31, 2016 is 132 mW. The total commitment to purchase power under these contracts on a nominal basis is approximately $975 million net of power sellbacks over the contract term. In February 1996, the Company reached an agreement with Hydro-Quebec which lowered the 1997 cost of power by approximately $5.8 million. As part of this agreement, the Company delivers to NEPOOL under existing firm energy contracts or joint marketing activities 54 mW of Phase II transmission capacity for a five-year period which began July 1, 1996 through June 30, 2001. In the early phase of the VJO contract, two sellback contracts were negotiated, the first delaying the purchase of about 25 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. There are specific contractual step up provisions that provide that in the event any VJO member fails to meet its obligation under the contract with Hydro-Quebec, the balance of the VJO participants, including the Company, will "step up" to the defaulting party's share on a pro-rata basis. As of December 31, 1999 the Company's VJO obligation is approximately 43% or $975 million on a nominal basis over the contract ending in 2016. The total VJO contract obligation on a nominal basis over the term of the contract is approximately $2.1 billion. During January 1998, a significant ice storm affected parts of New England and the Province of Quebec, Canada. This storm damaged major components of the Hydro-Quebec transmission system over which power is supplied to Vermont under the VJO contract with Hydro-Quebec. This resulted in a 61-day interruption of a significant portion of scheduled contractual energy deliveries into Vermont. The ice storm's effect on Hydro-Quebec's transmission system caused the VJO to examine Hydro-Quebec's overall reliability and ability to deliver energy. On the basis of that examination, the VJO determined that Hydro-Quebec has been and remains unable to make available capacity with the degree of firmness required by the VJO Power Contract. That determination has prompted the VJO to initiate an arbitration proceeding. In the arbitration, the VJO is seeking to terminate the contract, to recover damages associated with Hydro-Quebec's failure to comply with the contract, and to recover capacity payments made during the period of non-delivery. In September 1999 an initial two weeks of hearings were held dealing primarily with issues of contract interpretation. Additional hearings dealing with technical issues will be held in the second and third quarters of 2000. The company expects a decision by the end of 2000. In accordance with a PSB Accounting Order, the Company has deferred incremental costs associated with this arbitration of approximately $2.0 million. Recovery of these costs will be determined in the next rate proceedings. Merrimack #2 Until its termination on April 30, 1998, the Company purchased power and energy from Merrimack #2 pursuant to a contract dated July 16, 1966 entered into by and between VELCO and Public Service Company of New Hampshire ("PSNH"). Pursuant to the contract, as amended, VELCO agreed to reimburse PSNH, in the proportion which the VELCO quota bears to the demonstrated net capability of the plant, for all fixed costs of the unit and operating costs of the unit incurred by PSNH, which are reasonable and cost-effective for the remaining term of the VELCO contract. In early 1998, PSNH took the Merrimack Unit #2 facility off line, shut it down and commenced a maintenance outage. In February, March and April of 1998, PSNH billed VELCO for costs to complete the maintenance outage. VELCO disputes the validity of a portion of the charges on grounds that the maintenance performed at the unit was to extend the life of the Merrimack plant beyond the term of the VELCO contract and that the charges in connection with said investments were not reasonable and cost-effective for the remaining term of the VELCO contract. The Company estimates the portion of the disputed charges allocable to the Company could be as much as $.5 million on a pre-tax basis. Other Purchases. Cogeneration/Independent Power Qualifying Facilities - A number of independent producers using hydroelectric, biomass, and refuse-burning generation are currently producing energy that the Company is purchasing. For the year ended December 31, 1999, the Company received 193,114 mWh from these sources for which it paid $21,187,747. The Company, through VELCO, is a participant in NEPOOL, which has been open to all investor-owned, municipal, and cooperative utilities in New England under an agreement in effect since 1971 and amended from time to time. The Restated NEPOOL Agreement offers membership privileges to any entity which is engaged or proposes to engage in the wholesale or retail electric power business in New England. NEPOOL's function has changed in response to the growing climate of competition and the FERC requirements for open access transmission across systems. A new organization, an Independent System Operator ("ISO"), has been formed to operate the bulk power generation and transmission systems, to administer the regions open access transmission tariff, and to operate the electric ISO wholesale power market for New England. The bilateral market for transactions directly between NEPOOL participants will continue as an alternative to the ISO wholesale spot market. The ISO is governed by the principles put forth in the FERC Order 888 under rules defined by NEPOOL and approved by FERC. They include: to provide independent, open and fair access to the regional transmission system, to establish a non-discriminatory governance structure, to facilitate market-based wholesale electric transactions, and to ensure the efficient management and reliable operation of the regional bulk power system. The ISO has established a bidding system for the newly defined generation products; it will form the basis for the ISO's economic dispatch (based on bid prices) of the generation products. This system provides a settlement mechanism which will price the residual of a given generation product that is excess to a participant's own needs, and is offered to the ISO wholesale power market. A participant will pay, as before, the actual costs for its generation products used to serve its load or takes to market. A participant will submit a bid for its generation products to the ISO, and if the bid is accepted and if the participant supplies residual generation products to the ISO wholesale market, the participant will receive the market clearing price based on the highest bids accepted for the residual product. If a participant needs to purchase from the ISO wholesale market to serve its load, those purchases will be made at market clearing price. The ISO will also provide the main market place for participants to secure open access transmission for transactions delivered on the Pool Transmission Facilities ("PTF"). Over the next several years, the pricing differences that had existed between transmission systems within NEPOOL will disappear as a NEPOOL-wide transmission pricing arrangement for all PTF and the open access tariffs of local network providers will offer access to all other transmission facilities. The Company's peak demand for 1999 occurred on December 28 and equaled 420.5 mW. At the time of this peak, the Company had a reserve margin of 29%. NEPOOL's peak for the year occurred on July 7, 1999 and totaled 22,544 mW. 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 continue to utilize cost effective demand side management programs where appropriate. The Company will offer other retrofit energy efficiency services as part of a least-cost plan for electricity delivery. In addition, the Vermont state-wide Energy Efficiency Utility will offer energy efficiency services funded by a line item charge on each customer's bill. 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. 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, 1999 and 125,000 shares of Class C preferred stock, of which 100,000 shares were outstanding at December 31, 1999. On that date there were authorized and outstanding three issues of First Mortgage Bonds, aggregating $29,236,000, 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 2000 to transmit power to Vermont utilities. The costs of such facilities are presently estimated at $15,170,314 including allowance for funds used during construction calculated at a rate of approximately 6.5%. 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 it owns (which VELCO does not now do), VELCO would have the right to purchase all such firm power not sold to others. As such, VELCO would have the obligation to pay associated 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 Power Corporation 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, 1999) of capital contributions from VELCO and has entered into Transmission Line Support Agreements with 20 New England utilities, including VELCO as representative for 14 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. Pursuant to a Vermont Participation Agreement and a Capital Funds Support Agreement with VELCO and 14 Vermont electric distribution utilities, including the Company, 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, 1999 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 4.56% 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 the 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. 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. 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. However, during 1999, the Company worked with legislators and the PSB to transfer energy efficiency programs from the utilities to an independent agent of state government. The PSB has approved the creation of a state-wide Energy Efficiency Utility which it is expected to begin operating in the first half of 2000. 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, 1999 the Company and its wholly owned subsidiaries employed 542 persons, of which 217 are represented by the union. On December 30, 1998, the Company and its employees represented by the union agreed to a three-year contract, which expires on December 31, 2001. The new contract provides for a general wage increase of 2.6% effective January 1, 1999, January 2, 2000 and December 31, 2000. Under the terms of the new agreement, Company's employees represented by the union will contribute weekly pre-tax premiums for medical coverage of eight, nine and ten dollars effective July 1, 1999, January 1, 2000 and January 1, 2001, 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. OFFICERS The following sets forth the Executive Officers of the Company. 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, 52 President and Chief 1987 Executive Officer Francis J. Boyle, 54 Senior Vice President, 1995 Chief Financial Officer and Treasurer Kent R. Brown, 54 Senior Vice President- 1996 Engineering and Operations William J. Deehan, 47 Vice President-Regulatory 1991 Affairs and Strategic Analysis Joan F. Gamble, 42 Assistant Vice President, 1998 Human Resources and Strategic Planning Joseph M. Kraus, 44 Senior Vice President, 1987 Secretary and General Counsel James M. Pennington, 44 Vice President, Controller and 1993 Principal Accounting Officer Robert E. Rogan, 40 Vice President, Public Affairs 1998 Douglas D. Sinclair, 51 Vice President and General 1997 Manager for Business Development Carl G. Zeller, Jr., 46 Assistant Vice President and 1999 Servco Manager L. Douglas Barba, 51 Executive Vice President and 1992 General Manager - Catamount Energy Corporation
Mr. Young joined the Company in 1987. He was elected Senior Vice President - Finance and Administration in 1988. He previously served as Senior Vice President and Chief Operating Officer commencing in 1993 and Director, President and Chief Executive Officer commencing in 1995. Mr. Boyle joined the Company in October 1995. Prior to being elected to his present position in 1997, Mr. Boyle served as Vice President - Finance and Administration and Chief Financial Officer. Mr. Boyle served as Chief Financial Officer of Westmoreland Coal Company ("Westmoreland") in Philadelphia, Pennsylvania from 1993 to 1995. 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. Mr. Brown joined the Company in September 1996. Prior to being elected to his present position in 1997, he served as Vice President - Engineering and Operations commencing in 1996. From 1992 to 1995 he served as Chairman, President and Chief Executive Officer of Kansas Gas and Electric Company. Mr. Deehan joined the Company in 1985. Prior to being elected to his present position in 1996, he served as Assistant Vice President - Rates and Economic Analysis commencing in 1991. Ms. Gamble joined the Company in 1989. Prior to being elected to her present position in May 1998, she was Director of Marketing research & Planning from 1989 to 1996; Director of Strategic and Policy Planning from 1996 to September 1997 and Director of Human Resources and Strategic Planning from September 1997 to May 1998. Mr. Kraus joined the Company in 1981. Prior to being elected to his present position in 1999, he served as Vice President, Corporate Secretary and General Counsel commencing in 1996 and Corporate Secretary and General Counsel commencing in 1994. Mr. Pennington joined the Company in 1989. Prior to being elected to his present position in 1992, Mr. Pennington was designated Acting Controller effective July 19, 1992, and was elected Controller and named Principal Accounting Officer in 1993. Mr. Rogan joined the Company in 1998 as Vice President, Public Affairs. Prior to joining the Company, he served as Deputy Chief of Staff for the Governor of Vermont from 1994 to 1998. He served as Director of External Affairs for the Agency of Health Care Administration in Florida from 1992 to August 1994. Mr. Sinclair joined the Company April 1997 as Vice President and General Manager for Business Development. Prior to joining the Company, from 1994 to 1996 he served as President and Chief Executive Officer at Noma International. In 1991 he joined Novatel Communications, Ltd. As Chief Financial Officer and was President and Chief Executive Officer of Novatel Carmcom, Inc. From 1992 to 1994. Mr. Zeller joined the Company in 1998. Prior to being elected to his present position in 1999, he was (and remains) Director of Information Systems and Technology. From 1989 to 1998, he was a Senior Associate at Booz, Allen & Hamilton, Inc., a technology and management consulting firm. Mr. Barba joined Catamount Energy Corporation, a subsidiary of Catamount Resources Corporation (a wholly owned subsidiary of the Company), in August 1992. Prior to being elected to his present position in 1999, he served as Senior Vice President and General Manager in 1992. The term of each officer is for one year or until a successor is elected. Item 2. Properties. The Company. The Company's properties are operated as a single system which is interconnected by transmission lines of VELCO, NEP 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 47.35% joint-ownership interest in a transmission interconnection with Hydro-Quebec in Vermont. The electric transmission and distribution systems of the Company include about 614 miles of overhead transmission lines, about 7,371 miles of overhead distribution lines and about 273 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 433 miles of overhead distribution lines and about 12 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 August 7, 1997, the Company and eight other non-operating owners of Unit #3 filed a demand for arbitration with Connecticut Light and Power Company and Western Massachusetts Electric Company, both NU affiliates, and lawsuits against NU and its trustees. The arbitration and lawsuits seek to recover costs associated with replacement power, operation and maintenance costs and other costs resulting from the shutdown of Unit #3. The non-operating owners claim that NU and two of its wholly owned subsidiaries failed to comply with NRC's regulations, failed to operate the facility in accordance with good operating practice and attempted to conceal their activities from the non-operating owners and the NRC. A mediator has been hired in an attempt to settle prior arbitration and the lawsuit. On September 15, 1999, NU announced that it intends to auction its nuclear generating plants, including Unit #3. We cannot predict at this time the effect of such an auction, if it occurs, on the Company or on the ongoing litigation. On October 27, 1999, NU and NEP, disclosed that NU had reached an agreement with NEP and MEC, two of the non-operating minority joint owners, to settle their claims in the arbitration and lawsuits. The settlement involves payment of fixed and contingent amounts to NEP and MEC and the inclusion of their Unit #3 interests in NU's auction of the plant. In addition, on January 28, 2000 Central Maine Power Company ("CMP"), also one of the non-operating minority joint owners, disclosed that NU and CMP had reached an agreement to settle CMP's claims in the arbitration and litigation. However, no terms of the agreement have been disclosed by CMP. The other non-operating minority joint owners, including the Company, remain active in the arbitration and lawsuits and in seeking to settle our claims against NU. Except as otherwise described under Management's Discussion and Analysis of Financial Condition and Results of Operations, Item 7, 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 1999. 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. Newspaper listings of stock transactions use the abbreviation CVtPS or CentlVtPS and the Internet trading symbol is 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 1999 First quarter.............. $ 13 $ 9 7/8 Second quarter............. 13 9 9/16 Third quarter.............. 14 7/16 12 3/8 Fourth quarter............. 13 7/8 10 3/16 1998 First quarter.............. $ 15 7/16 $ 13 1/8 Second quarter............. 15 1/4 14 5/16 Third quarter.............. 14 15/16 9 3/4 Fourth quarter............. 11 1/2 9 3/4
(b) As of December 31, 1999, there were 10,862 holders of the Company's Common Stock, $6 par value. (c) Common stock dividends have been declared quarterly. Cash dividends of $.22 per share were paid for all quarters of 1998 and 1999. 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, 1999, the Common Stock Equity of the unconsolidated Company was 50.1% 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) 1999 1998 1997 1996 1995 For the year - - - - - - - - - - - - - - - - - ------------ Operating revenues $419,815 $303,835 $304,732 $290,801 $288,277 Net income before extraordinary charge $ 16,584 $ 3,983 $ 17,151 $ 19,442 $ 19,851 Extraordinary charge net of taxes $ - $ - $ 811 $ - $ - Net income $ 16,584 $ 3,983 $ 16,340 $ 19,442 $ 19,851 Earnings available for common stock $ 14,722 $ 2,038 $ 14,312 $ 17,414 $ 17,823 Consolidated return on average common stock equity 7.9% 1.1% 7.5% 9.4% 10.0% Earnings per basic and diluted share of common stock before extraordinary charge $1.28 $.18 $1.32 $1.51 $1.53 Earnings per basic and diluted share of common stock $1.28 $.18 $1.25 $1.51 $1.53 Cash dividends paid per share of common stock $.88 $.88 $.88 $.84 $.80 Book value per share of common stock $16.05 $15.63 $16.38 $16.19 $15.51 Net cash provided by operating activities $ 31,232 $ 21,743 $ 41,974 $ 43,007 $ 42,583 Dividends paid $ 11,950 $ 12,006 $ 12,630 $ 11,728 $ 11,350 Construction and plant expenditures $ 13,231 $ 16,046 $ 13,841 $ 18,952 $ 21,337 Conservation and load management expenditures $ 2,440 $ 2,208 $ 1,837 $ 1,589 $ 3,899 At end of year - - - - - - - - - - - - - - - - - -------------- Long-term debt $155,251 $ 90,077 $ 93,099 $117,374 $119,142 Capital lease obligations $ 15,060 $ 16,141 $ 17,223 $ 18,304 $ 19,385 Redeemable preferred stock $ 17,000 $ 18,000 $ 19,000 $ 20,000 $ 20,000 Total capitalization (excluding current portion of debt) $379,386 $311,454 $324,499 $350,201 $346,341 Total assets $563,959 $530,282 $531,940 $502,968 $489,213
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. Earnings Overview The Company's 1999 net income was $16.6 million or $1.28 per share of common stock, which equates to a 7.9% return on average common equity. Net income and earnings per share of common stock for 1999 compares to $4.0 million and $.18 in 1998, and $16.3 million and $1.25 in 1997. The return on average common equity was 1.1% for 1998 and 7.5% for 1997. Improved 1999 earnings versus 1998 resulted primarily from higher retail revenues associated with the positive impact of a 4.7% temporary Vermont rate increase ($7.1 million after-tax, or $.61 per share of common stock) as well as a 2.0% increase in retail mWh sales ($2.6 million after-tax, or $.23 per share of common stock). In addition, net income and earnings per share of common stock for 1999 reflect the positive effect of reversing $4.3 million after-tax, or $.38 per share of common stock, resulting from disallowed Hydro-Quebec purchased power costs in the same amount accrued during the fourth quarter of 1998, and the reversal of 1998 charges during 1999 of $4.3 million after-tax, or $.38 per share of common stock. This positive effect was offset by the recognition of 2000 disallowed Hydro-Quebec power costs of about $1.7 million after-tax, or $.15 per share of common stock, in the fourth quarter of 1999. Net income and earnings per share of common stock were also affected by non-utility losses of $2.5 million after-tax, or $.22 per share of common stock, related to SmartEnergy Services, Inc. ("SmartEnergy") proportionate share in Home Service Solutions LLC (d.b.a. The Home Service Store) ("HSS"), and Catamount Energy Corporation ("Catamount"), and higher operating and maintenance costs of $3.1 million after-tax, or $.28 per share of common stock, caused by two major storms in 1999 as well as increased regulatory and legal costs, partially offset by the favorable effect of Accounting Orders for the deferral of certain legal and regulatory costs of $1.3 million, or $.12 per share of common stock. Higher interest costs of $1.1 million, or $.10 per share of common stock, due to the sale of Second Mortgage Bonds and increases in average outstanding short-term debt. Lower power costs of $1.7 million after-tax, or $.14 per share of common stock, principally related to better performance at Unit #3 (Unit #3 was off-line during the first half of 1998) and Vermont Yankee Nuclear Power Corporation ("Vermont Yankee") plant due to the extended refueling outage in 1998, partially offset by higher power costs related to the Hydro-Quebec contract. For 1998 compared to 1997, net income and earnings per share of common stock for the Company's utility business reflects the negative impact of increased power costs under the Hydro-Quebec contract of $5.0 million after-tax, or $.44 per share of common stock, increased other power costs of $1.7 million after-tax, or $.15 per share of common stock, related to the longer than expected refueling outage at the Vermont Yankee Nuclear Power plant, higher operating and maintenance costs of $2.1 million after-tax, or $.18 per share of common stock caused by increased legal and regulatory costs as well as costs associated with the ice storm in January 1998. During April 1998 the Company agreed to toll the statutory period of time in which the Vermont Public Service Board ("PSB") must act on its pending 6.6% rate increase request filed in September 1997. At the same time, the Company asked the Vermont Supreme Court ("VSC") to review the PSB's denial of the Company's claim that the PSB is precluded from again trying the Company on certain Hydro-Quebec contract and demand side management decisions. The appeal and associated stay of the rate case significantly delayed the date that new rates would have otherwise taken effect. As a result, the Company's earnings for 1998 were adversely affected. Second, because of the October 27, 1998 retail rate increase settlement discussed below and in Note 13 to the Consolidated Financial Statements, net income and earnings per share of common stock for 1998 include the negative impact of an after-tax disallowance of $4.3 million, or $.38 per share of common stock for the Company's purchased power costs under the Hydro-Quebec Contract. Also, for 1998, net income and earnings per share of common stock for the Company's utility business reflects the net effect at Connecticut Valley of after-tax charges taken during the fourth quarter of 1998 of $3.7 million, or $.32 per share of common stock, offset by the reversal of 1997 after-tax charges during the first quarter of 1998 of $4.5 million, or $.39 per share of common stock. These charges and reversal of charges are discussed below and in Note 13 to the Consolidated Financial Statements. On June 12, 1998, the Company filed with the PSB a request for a 10.7% rate increase ($24.7 million of annualized revenues) effective March 1, 1999. On October 27, 1998, the Company reached an agreement with the Vermont Department of Public Service ("DPS") regarding this rate increase request. The agreement, which was approved by the PSB on December 11, 1998, provides for a temporary rate increase in the Company's Vermont retail rates of 4.7% or $10.9 million on an annualized basis beginning with service rendered January 1, 1999 and sets the Company's authorized return on common equity in its Vermont retail business at 11%. The rate increase is temporary insofar as it is subject to adjustment upon future resolution of the Hydro-Quebec Contract issues presently before the VSC discussed in Note 13 to the Consolidated Financial Statements. The Company filed for a 6.6% or $15.4 million general rate increase on September 22, 1997 to become effective June 6, 1998, which is now stayed pending a review by the VSC as more fully discussed in Note 13 to the Consolidated Financial Statements. 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 operating revenues and mWh sales for 1999, 1998 and 1997 is set forth below:
mWh Sales Revenues (000's) 1999 1998 1997 1999 1998 1997 Residential 948,756 930,666 945,199 $123,302 $115,911 $116,314 Commercial 943,141 937,547 916,311 109,440 103,221 104,460 Industrial 442,308 418,778 427,764 36,823 33,617 34,206 Other retail 6,235 7,123 7,138 1,787 1,943 1,937 --------- --------- --------- -------- -------- ------- Total retail sales 2,340,440 2,294,114 2,296,412 271,352 254,692 256,917 ========= ========= ========= ======== ======== ======= Resale sales: Firm 2,349 2,284 1,051 160 94 46 Entitlement 356,197 319,703 378,273 20,875 19,370 18,925 Alliance 2,986,682 357,400 - 100,116 11,266 - Other 869,857 651,235 827,818 22,121 15,595 22,265 --------- --------- --------- -------- -------- -------- Total resale sales 4,215,085 1,330,622 1,207,142 143,272 46,325 41,236 ========= ========= ========= ======== ======== ======== Other revenues - - - 5,191 2,818 6,579 --------- --------- --------- -------- -------- -------- Total 6,555,525 3,624,736 3,503,554 $419,815 $303,835 $304,732 ========= ========= ========= ======== ======== ========
Year-to-year fluctuations in total retail mWh sales are primarily affected by customer growth, 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. Compared to 1998, retail mWh sales for 1999 increased 46,326 mWh, or 2.0% and related revenues increased $16.7 million, or 6.5% compared to 1998. The revenue increase was primarily attributable to the 4.7% temporary Vermont retail rate increase discussed above and the impact of higher mWh sales. Compared to 1997, retail mWh sales for 1998 decreased 2,298 mWh and retail revenues decreased $2.2 million, or .9% compared to 1997. The revenue decrease was primarily attributable to a modified rate design reflected in bills rendered since April 1, 1997. The modified rate design, which was revenue neutral on an annual basis, decreased average prices slightly charged during 1998 from average levels for 1997. For 1999, entitlement mWh sales increased 11.4% compared to 1998. This increase resulted primarily from the Vermont Yankee extended refueling outage in 1998. Entitlement mWh sales for 1998 decreased 15.5% compared to 1997. The decrease resulted primarily from the scheduled refueling and maintenance outage of the Vermont Yankee plant. The outage, which reduced the plant's 1998 output, also reduced mWh sales. However, a portion of the higher costs of the Company's share of Vermont Yankee's costs associated with the refueling and maintenance outage was passed on to entitlement customers resulting in an increase in entitlement revenues of $.4 million, or 2.4%. For 1999 alliance resale sales increased 2,629,282 mWh and related revenues increased $88.9 million . This increase results from activity by the Company through its alliance with Virginia Power in jointly supplying wholesale power primarily in the Northeast states. In the third quarter of 1999 the Company decided to discontinue this alliance. Other resale sales increased 218,622 mWh for 1999 and decreased 176,583 mWh for 1998. Related revenues increased $6.5 million for 1999 and decreased $6.7 million for 1998. These variances reflect current market conditions in Vermont and New England and the greater availability of low cost energy in the region. These sales made on a short-term basis include sales to NEPOOL and other utilities in New England. Other revenues increased $2.4 million for 1999 compared to 1998 primarily due to refund obligations recorded in the fourth quarter of 1998 by Connecticut Valley as more fully discussed below. For 1998 compared to 1997 other revenues decreased due to a provision for rate refunds of $2.7 million related to a Fuel Adjustment Clause ("FAC") and Purchased Power Cost Adjustment ("PPCA") at Connecticut Valley, associated with the December 3, 1998 Court of Appeals' decision discussed below, and revenues of about $.7 million associated with transmission interconnection agreements in 1997 and lower revenues from pole attachment rentals. The table below summarizes the components of increases or decreases in revenues compared to the prior year (dollars in thousands):
1999 1998 Revenue increase (decrease) from: Retail MWh sales $ 4,516 $ (90) Retail rates 12,144 (2,135) Changes in firm resale sales 66 48 Changes in entitlement sales 1,505 445 Change in alliance sales 88,850 11,266 Changes in other resale sales 6,526 (6,670) Changes in other revenues 2,373 (3,761) -------- ------- Net increase over prior year $115,980 $ (897) ======== =======
Purchased power - The Company purchases approximately 90% of its power needs under several contracts of varying duration. Over 30% of its 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, excluding sources related to the Company's alliance with Virginia Power discussed above, is shown below:
Year Ended December 31 1999 1998 1997 Nuclear generating companies 34% 37% 36% Canadian imports 35 31 32 PSNH-coal - 2 9 Company-owned hydro 5 7 5 Jointly owned units 6 3 1 Independent power producers 5 6 6 Other sources 15 14 11 --- --- --- 100% 100% 100% === === ===
The Company maintains a 1.7303% joint-ownership interest in 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. The Company's entitlement percentage for Vermont Yankee is 35%. 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. Millstone Unit #3 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 and Northeast Utilities Service Co.'s efforts relating to Unit #3. On August 7, 1997, the Company and eight other non-operating owners of Unit #3 filed a demand for arbitration with Connecticut Light and Power Company and Western Massachusetts Electric Company, both NU affiliates, and lawsuits against NU and its trustees. The arbitration and lawsuits seek to recover costs associated with replacement power, operation and maintenance costs and other costs resulting from the lengthy outage of Unit #3. The non-operating owners claim that NU and two of its wholly owned subsidiaries failed to comply with NRC's regulations, failed to operate the facility in accordance with good operating practice and attempted to conceal their activities from the non-operating owners and the NRC. On September 15, 1999, NU announced that it intends to auction its nuclear generating plants, including Unit #3. We cannot predict at this time the effect of such an auction, if it occurs, on the Company or on the ongoing litigation. On October 27, 1999, NU and NEP, disclosed that NU had reached an agreement with NEP and MEC, two of the non-operating minority joint owners, to settle their claims in the arbitration and lawsuits. The settlement involves payment of fixed and contingent amounts to NEP and MEC and the inclusion of their Unit #3 interests in NU's auction of the plant. On January 28, 2000, Central Maine Power Company ("CMP"), also one of the non-operating minority joint owners, disclosed that NU and CMP had reached an agreement to settle CMP's claims in the arbitration and litigation. However, no terms of the agreement have been disclosed by CMP. The other non-operating minority joint owners, including the Company, remain active in the arbitration and lawsuits and in seeking to settle our claims against NU. Based on the most recent decommissioning estimate in 1997, the Company's total share of Unit #3 decommissioning costs at December 31, 1999 was $10.7 million. As of December 31, 1999, the Company has funded $4.0 million of these costs. Vermont Yankee The Vermont Yankee nuclear power plant, which provides more than one-third of the Company's power supply, began a refueling outage on October 29, 1999 and returned to service on December 2, 1999. The 1998 refueling outage (March 21 - June 3) extended 26 days beyond the scheduled 49 days. Vermont Yankee had no scheduled refueling outage in 1997. During scheduled nuclear 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 Vermont Yankee nuclear power plant and Unit #3, a jointly owned nuclear generating unit. During 1999, the Company deferred $2.1 million and $6.8 million for replacement energy and maintenance costs, respectively. During 1996, Vermont Yankee initiated a Design Basis Documentation project expected to be complete by December 31, 2001. This project was undertaken to incorporate all design documentation into a centralized system. The objective is to ensure that Vermont Yankee maintains its safety margins in connection with any plant modifications. The Design Basis Documentation project will create a set of design basis documents which will support more efficient systematic problem solving, maintenance, and system overview. This effort supports the safe, cost effective, long term operation of the Vermont Yankee Plant. Vermont Yankee received FERC approval in 1996 to defer these unrecovered study costs and amortize the costs through billings to Sponsors over the remaining license life of the Plant. The Company's 35% share of the total cost for this Project is expected to be between $5.5 million and $6.2 million. On October 15, 1999 the Company and the other owners of Vermont Yankee accepted a bid for sale of the plant to AmerGen Energy Co., which is owned by PECO Energy Company and British Energy. On November 17, 1999, Vermont Yankee executed an Asset Purchase Agreement with AmerGen Energy Co. The Agreement is subject to several conditions, including approvals or specific rulings by various regulatory authorities. As such, execution of the Agreement does not provide assurance that the sale will occur. This agreement will also involve the Company entering into a contract to purchase a portion of the power produced by this plant. The price to be paid by AmerGen for the plant and property will range from $10 million to $23.5 million depending on when the sale occurs. Additionally, Vermont Yankee's current owners will make a one-time payment of $54.3 million to pre-pay the plant's decommissioning fund at $312.7 million. In return, AmerGen will assume full responsibility for all future operating costs and the estimated $816.6 million price tag for decommissioning the plant at the end of its operating license in 2012. Maine Yankee On August 6, 1997, the Maine Yankee's nuclear power plant was prematurely retired from commercial operation. The Company relied on Maine Yankee for less than 5% of its required system capacity. Future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee are estimated to be approximately $715.0 million in 1998 dollars including a decommissioning obligation of $344.0 million. On January 19, 1999, Maine Yankee and the active intervenors filed an Offer of Settlement with the FERC which the FERC has approved. As a result, all issues raised in the FERC proceeding, including recovery of anticipated future payments for closing, decommissioning and recovery of the remaining investment in Maine Yankee are resolved. Also resolved are the issues raised by the secondary purchasers, who purchased Maine Yankee power through agreements with the original owners, by limiting the amounts they will pay for decommissioning the Maine Yankee plant and by settling other points of contention affecting individual secondary purchasers. As a result, it is possible that the Company will not be able to recover approximately $.5 million of these costs. Connecticut Yankee On December 4, 1996, the Connecticut Yankee Nuclear power plant was prematurely retired from commercial operation. The Company relied on Connecticut Yankee for less than 3.0% of its required system capacity. On August 31, 1998, a FERC Administrative Law Judge recommended that the owners of Connecticut Yankee, including the Company, may collect from customers $350.0 million for decommissioning the Connecticut Yankee Nuclear Power Plant rather than the $426.7 million requested. The Administrative Law Judge ruling is subject to approval by the FERC Commissioners. If approved, it is possible that the Company would not be able to recover approximately $1.5 million of decommissioning costs through the regulatory process. Yankee Atomic In 1992, the Yankee Atomic nuclear power plant was retired from commercial operation. The Company relied on Yankee Atomic for less than 1.5% of its system capacity. Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs Presently, costs billed to the Company by Maine Yankee, Connecticut Yankee and Yankee Atomic, including a provision for ultimate decommissioning of the units, are being collected from the Company's customers through existing retail and wholesale rate tariffs. The Company's share of remaining costs with respect to Maine Yankee, Connecticut Yankee and Yankee Atomic's decisions to discontinue operation is estimated to be $12.8 million, $8.4 million and $.9 million, respectively, at December 31, 1999. These amounts are subject to ongoing review and revisions and are reflected in the accompanying balance sheet both as regulatory assets and nuclear dismantling liabilities (current and non-current). The decision to prematurely retire these nuclear power plants was based on economic analyses of the costs of operating them compared to the costs of closing them and incurring replacement power costs over the remaining period of the plants' operating licenses. The Company believes that based on the current regulatory process, its proportionate share of Maine Yankee, 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 three plants has not and should not have a material adverse effect on the Company's earnings or financial condition. Merrimack Unit #2 Until its termination on April 30, 1998, the Company purchased power and energy from Merrimack Unit #2 pursuant to a contract dated July 16, 1966 entered into by and between VELCO and PSNH. See Note 14 to the Consolidated Financial Statements for further details related to the Merrimack Unit #2 contract. Cogeneration/Independent Power Qualifying Facilities A number of IPPs using hydroelectric, biomass, and refuse-burning generation are currently producing energy that the Company is purchasing. The majority of these purchases are made from a state appointed purchasing agent who purchases and redistributes the power to all Vermont utilities. Under these long-term contracts, in 1999 the Company received 193,114 mWh of which 139,407 mWh is associated with the Vermont Electric Power Producers and 37,309 mWh with the New Hampshire/Vermont Solid Waste Plant owned by Wheelabrator Claremont Company, L.P. The Company expects to purchase approximately 205,821 mWh of independent power output in each year 2000 to 2004. Based on the forecast level of production, the total commitment in the next five years to purchase power from these independent power facilities is estimated to be $118.4 million. As part of the Company's initiative to cut power costs and restructure Vermont's utility industry, on August 3, 1999, the Company, Green Mountain Power ("GMP"), Citizens Utilities and all of Vermont's 15 municipal utilities, filed a petition with the PSB requesting modification of the contracts between the IPPs and the state appointed purchasing agent. The petition is based on unique provisions of the existing contracts and PSB regulations that provide for modifications and alterations that serve the public interest. The petition outlines seven specific elements that, if implemented, would reduce the purchase power costs of these contracts. On September 3, 1999, the PSB responded to the Company's petition by opening a formal investigation regarding these contracts. Shortly thereafter, Citizens Utilities, Hardwick Electric Department and the Burlington Electric Department notified the PSB that they were withdrawing from the petition but they will participate in the case as a non-moving parties. In a separate VSC action brought by several IPP's owners, GMP's full participation in this PSB proceeding was enjoined. That injunction is now on appeal to the VSC. The Company and the other moving utilities have requested that the PSB issue an order requiring GMP's full participation in the PSB proceeding. At the same time, the IPPs have filed a motion seeking to disqualify the law firm representing the utilities on the grounds of an alleged conflict of interest. The Company has also filed a related proceeding in the Washington County Superior Court contending that the PSB rules pertaining to IPPs, which the utilities have relied upon, in part, in their petition before the PSB contains a so-called "scrivener's error". Other In order to optimize its power mix for baseload, intermediate and peaking power, the Company engages in purchases and sales with other electric utilities primarily in New England and with NEPOOL to take advantage of immediate pricing and other market conditions. The profits from these transactions are used to reduce purchased power costs. These purchases are included in Other sources in the Sources of Energy table above. In addition, in 1999 and 1998, the Company also engaged in marketing activities with Virginia Power which jointly supply wholesale power primarily in the Northeast states discussed above. These purchases are excluded from the sources of energy table above. In the third quarter of 1999, the Company decided to discontinue this alliance. The net cost components of purchased power and production fuel costs for the past three years were as follows (dollars in thousands):
1999 1998 1997 ---- ---- ---- Units Amount Units Amount Units Amount ----- ------ ----- ------ ----- ------ Purchased and produced: Capacity (mW) 845 $ 96,769 613 $104,740 527 $ 99,513 Energy (mWh) 6,369,412 172,691 3,478,860 80,147 3,470,235 71,930 -------- -------- -------- Total purchased power costs 269,460 184,887 171,443 Production fuel (mWh) 402,355 3,165 332,835 1,996 237,064 1,820 -------- -------- -------- Total purchased power and production fuel costs 272,625 186,883 173,263 Less entitlement and other resale sales (mWh) 4,212,736 143,112 1,328,338 46,231 1,206,091 41,190 -------- -------- -------- Net purchased power and production fuel costs $129,513 $140,652 $132,073 ======== ======== ========
For 1999, purchased capacity costs decreased $8.0 million over 1998. This decrease was primarily due to the positive impacts of recognizing in 1998 disallowed 1999 Hydro-Quebec power costs of $7.4 million (pre-tax) and disallowed 1999 Connecticut Valley's power costs of $1.6 million (pre-tax). Partially offsetting this decrease is scheduled cost increases under the Hydro-Quebec contract of $3.0 million and the recognition in 1999 of disallowed first quarter 2000 Hydro-Quebec power costs of $2.9 million (pre-tax), disallowed 2000 Connecticut Valley's power costs of $1.2 million (pre-tax), both charged in the fourth quarter of 1999, as well as higher costs, in 1998, for the Vermont Yankee extended outage ($1.7 million pre-tax). For 1998, purchased capacity cost increased $5.2 million over 1997. This increase was the result of a $7.4 million disallowance of Hydro-Quebec power costs discussed below, $7.2 million of higher costs primarily associated with the Hydro-Quebec contract, the Vermont Yankee extended outage and $1.6 million of disallowed power costs at Connecticut Valley. Offsetting this increase was the impact at Connecticut Valley totaling $11.0 million associated with the reversal of a $5.5 million charge-off during 1998 and charge-off during 1997 of $5.5 million. See Electric Industry Restructuring-New Hampshire discussed below and Note 13 to the Consolidated Financial Statements for additional information. Pursuant to a PSB Accounting Order, during the first half of 1997, the Company reduced capacity costs by $5.8 million related to the Hydro-Quebec agreement for which a payment of $5.8 million was received from Hydro-Quebec on June 30, 1997. 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. Energy purchases increased $92.5 million for 1999 primarily from an 8%, or $5.8 million increase in the amount of mWh purchased offset by a $3.8 million decrease in price and $90.4 million associated with Virginia Power Alliance (2,629,282 mWh). The increase in the Virginia Power Alliance purchases was offset by increases in alliance resale sales discussed above. The increase in energy costs for 1998 resulted from an 11.1% or, $8.0 million increase in cost per mWh purchased and a $.2 million increase in the amount of mWh purchased. The price increase resulted primarily from the higher costs under the Hydro-Quebec power contract, increased purchases from IPPs, the Vermont Yankee extended outage and Virginia Power Alliance purchases (357,400 mWh - $10.2 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. For additional information see Notes 2 and 14 to the Consolidated Financial Statements. 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. Primarily due to increased generation by the Company's joint-ownership units, production fuel costs increased for 1999 compared to 1998. Based on present commitments and contracts, the Company expects that net purchased power and production fuel costs will be approximately $137.7 million, $144.5 million and $145.6 million for the period 2000 through 2002. Other operation expenses - The increase in other operation expenses of approximately $2.9 million and $3.2 million for 1999 and 1998, respectively, resulted primarily from increased regulatory and legal costs as well as increased conservation and load management costs. The 1999 increase was partially offset by the favorable effect of Accounting Orders for the deferral of certain legal and regulatory costs of $2.2 million. See Note 14 to the Consolidated Financial Statements for related information. Maintenance expenses - The increase in maintenance expenses of $2.0 million for 1999 is primarily due to higher costs related to two major storms in 1999 as well as increased costs related to Unit #3. For 1998 Maintenance expenses associated with the Company's joint- ownership interest in Unit #3 decreased compared to 1997. However, this decrease was offset by an increase in maintenance expenses associated with the Company's tree trimming program and expenses attributable to a severe ice storm in January 1998. Income taxes - Federal and state income taxes fluctuate with the level of pre-tax earnings in relation to permanent differences. For 1999 these taxes increased as a result of an increase in pre-tax earnings and no change in permanent differences for the period. Income taxes decreased for 1998 as a result of lower pre-tax earnings and no change in permanent differences for the period. Other income and deductions - Other income and deductions decreased for 1999 and 1998. The 1999 decrease was primarily due to lower equity income from non-utility subsidiary companies primarily related to SmartEnergy's proportionate share in HSS. The 1998 decrease resulted from gains of $5.0 million from non-recurring asset sales in 1997. Interest on long-term debt - In July 1999, the Company sold $75.0 million aggregate principal amount of 8 1/8% Second Mortgage Bonds due 2004. Accordingly, interest on long-term debt increased for 1999. This increase was partially offset by the retirement of long-term debt in December 1998. Other interest expense - Other interest expense increased for 1999 and 1998 due to increases in average outstanding short-term debt. Extraordinary credit - As a result of legal and regulatory actions associated with Connecticut Valley, the Company, in 1997, recorded an extraordinary charge of $.8 million. See Electric Industry Restructuring-New Hampshire below. Cash Dividends Declared - For 1997 common dividends declared included an early declaration made in December 1997 for the quarterly dividend paid on February 13, 1998. Liquidity and Capital Resources 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 $31.2 million in 1999, $21.7 million in 1998 and $42.0 million in 1997. The Company ended 1999 with cash and cash equivalents of $35.5 million, an increase of $25.4 million from the beginning of the year. The increase in cash for 1999 was the result of $31.2 million provided by operating activities, $29.9 million used for investing activities and $24.1 million provided by financing activities. Operating Activities - Net income, depreciation and deferred income taxes and investment tax credits provided $35.5 million. $4.3 million was used for fluctuations in working capital and other operating activities. Investing Activities - Construction and plant expenditures consumed $13.2 million while $16.8 million was used for C&LM programs and non-utility investments. $.1 million was provided by other investing activities. Financing Activities - Dividends paid on common stock were $10.1 million, while preferred stock dividends were $1.8 million. Retirement of long-term debt and retirement of preferred stock required $3.2 million and $1.0 million, respectively, and reduction in capital lease obligations required $1.1 million. Short-term obligations required $40.6 million and issuance of long-term debt provided $81.9 million. Excluding allowance for funds used during construction, construction expenditures are estimated at $17.7 million, $18.1 million and $18.8 million for the years 2000 through 2002, respectively. The level of short-term borrowings fluctuates based on seasonal corporate needs, the timing of long-term financings and market conditions. On July 30, 1999 the Company sold $75.0 million aggregate principal amount of 8 1/8% Second Mortgage Bonds due 2004 at a price of 99.915% in accordance with Securities and Exchange Commission Rule 144A. The net proceeds of the offering were used to repay $15.0 million of outstanding loans under the Company's revolving credit facility and are expected to be used for other general corporate purposes relative to the Company's utility business. In addition, the Company canceled its $40.0 million revolving credit facility. The bonds were registered under the Securities Act of 1933 on November 15, 1999. The Company has an aggregate of $16.9 million of letters of credit with termination dates of May 31, 2000. In addition, the Company had a $12.0 million accounts receivable facility which was repaid by the Company in November 1999. On March 12, 1999, Connecticut Valley was notified by Citizens Bank of New Hampshire ("Bank"), that it would exercise appropriate remedies in connection with the violation of financial covenants associated with the $3.75 million loan agreement with the Bank unless the violation was cured by April 11, 1999. To avoid default of this loan agreement, on April 6, 1999, pursuant to an agreement reached on March 26, 1999, the Company purchased from the Bank the $3.75 million note. The Company, through a common stock repurchase program initiated in 1994 and subsequently suspended in order to preserve capital for use in industry restructuring and other business purposes, purchased 362,447 shares of its common stock in open market transactions during 1995, 1996 and 1997 at an average price of $13.04 per share. These transactions, net of 43,404 shares sold in connection with the Company's stock option plans, are recorded as treasury stock, at cost, in the Company's Consolidated Balance Sheet. 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 1999 1998 1997 Common stock equity 47% 56% 54% Preferred stock 6 8 8 Long-term debt 43 31 33 Capital lease obligations 4 5 5 --- --- --- 100% 100% 100% === === ===
On February 2, 1999, Standard & Poor's Corporation ("Standard & Poor's") lowered its corporate credit rating on the Company to triple-'B'-minus from triple-'B', the senior secured rating to triple-'B'-plus from single-'A'-minus, and the preferred stock rating to double-'B'-plus from triple-'B'-minus. In addition, the ratings were also placed on CreditWatch with negative implications. On February 17, 1999, Standard & Poor's rating on the Company's preferred stock was automatically reduced to double-'B'- from double -'B'- plus in response to a policy change in the way Standard & Poor's rates preferred stock. Standard & Poor's stated "the CreditWatch listing reflects the potentially adverse impact of pending legal and regulatory decisions that could seriously weaken the Company's credit profile. The downgrades reflect increased business risk and weakened financial measures as a result of recent regulatory decisions in Vermont and New Hampshire and an adverse ruling by the United States First Circuit Court of Appeals." Standard & Poor's also said "Resolution of the CreditWatch listing will depend on the outcome of the pending Federal Energy Regulatory Commission case and other legal proceedings at State and Federal levels. Adequate rate relief and successful mitigation of high power costs through contract renegotiations or other methods are essential to stabilizing the ratings." On July 16, 1999, Standard & Poor's assigned its triple-'B'- minus rating to the Company's then proposed $75.0 million second mortgage bonds. Concurrently, the bonds were placed on CreditWatch with negative implications. Standard & Poor's said "the second mortgage bonds are rated the same as the Company's corporate credit rating, and not notched up, because Standard & Poor's projects that the value of the Company's collateral will not substantially exceed the maximum combined amount of first and second mortgage bonds that could be outstanding under the terms of their respective indentures in a default scenario." On February 17, 1999, Duff & Phelps Credit Rating Co.("Duff & Phelps") placed the credit ratings of the Company on Rating Watch-Down due to the high level of regulatory and public policy uncertainty in Vermont and the recent unfavorable ruling by the United States Court of Appeals relating to Connecticut Valley, the Company's wholly owned New Hampshire subsidiary. Duff & Phelps stated "recent negative rulings by the PSB regarding purchased power costs and the high level of uncertainty with public policy toward electric utilities in Vermont adds risk to the Company's financial profile going forward". On July 16, 1999 Duff & Phelps lowered the preferred stock rating to 'BB+' (Double-B-plus) from 'BBB-' (Triple-B-minus) to reflect the new $75.0 million issuance of second mortgage bonds. Duff & Phelps credit ratings remain at 'BBB' (Triple-B) for first mortgage bonds. Current credit ratings of the Company's securities by Standard & Poor's and Duff & Phelps are as follows: Standard Duff & & Poor's(1) Phelps(2) -------- ------ Corporate Credit Rating BBB- N/A First Mortgage Bonds BBB+ BBB Second Mortgage Bonds BBB- BBB- Preferred Stock BB BB+ (1) All Standard & Poor's ratings are placed on "CreditWatch with negative implications". (2) All Duff & Phelps ratings are placed on "Rating Watch Down" On November 12, 1998, Catamount, replaced its $8.0 million credit facility with a $25.0 million revolving credit/term loan facility maturing November 2006 which provides for up to $25.0 million in revolving credit loans and letters of credit. This facility has a security interest in Catamount's assets. Catamount currently has a $1.2 million letter of credit outstanding to support certain of its obligations in connection with a debt service requirement in the Appomattox Cogeneration project. In addition, a letter of credit for $11.0 million is outstanding in support of construction and equity commitments for its Gauley River Power project. SmartEnergy Water Heating Services, Inc., a wholly owned subsidiary of SmartEnergy, has a secured seven-year term loan with Bank of New Hampshire with an outstanding balance of $1.3 million at December 31, 1999. The interest rate is fixed at 9.25%. Financial obligations of the Company's subsidiaries are non-recourse to the Company. The Company cannot assure that its business will generate sufficient cash flow from operations or that future borrowings will be available to the Company in an amount sufficient to enable the Company to pay its indebtedness, including the $75.0 million second mortgage bonds, when due or to fund its other liquidity needs. The Company's ability to repay its indebtedness is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory, weather and other factors that are beyond its control. The type, timing and terms of future financing that the Company may need will be dependent upon its cash needs, the availability of refinancing sources and the prevailing conditions in the financial markets. The Company cannot guarantee that financing sources will be available to the Company at any given time or that the terms of such sources will be favorable. Diversification Catamount Resources Corporation was formed for the purpose of holding the Company's subsidiaries that invest in non-regulated business opportunities. Catamount a subsidiary of Catamount Resources Corporation, invests in energy generation projects in North America and Western Europe. Through its wholly owned subsidiaries, Catamount has interests in seven operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Thetford, England; Hopewell, Virginia; and Fort Dunlop, England. In addition, Catamount has interests in a project under construction in Summersville, West Virginia. In November 1999 Catamount created a new subsidiary, Catamount Investment Company LLC, which will provide additional capital for investment in new generation projects. Catamount has partnered with CIT Group, a major equipment finance company, and Dana Commercial Credit Corporation, the finance subsidiary of Dana Corporation. Capital commitments from these two joint venture partners are $60.0 million, to be invested over the next four years. Catamount's after-tax earnings were $2.1 million, $3.3 million and $4.1 million for 1999, 1998 and 1997, respectively. SmartEnergy also a subsidiary of Catamount Resources Corporation invests in unregulated energy and service related businesses. SmartEnergy also has a 70% ownership interest in HSS. Overall, SmartEnergy incurred net losses of $2.9 million, $1.5 million and $.7 million for 1999, 1998 and 1997, respectively. HSS establishes a network of affiliate contractors who perform home maintenance repair and improvements via membership. Although SmartEnergy owns a 70% interest in HSS, this investment is accounted for using the equity method on the basis that financing plans will be completed in early 2000 which will have the effect of diluting SmartEnergy's ownership to a less than 50% level. HSS began operations in 1999 and is subject to risks and challenges similar a company in the early stage of development. HSS' pre-tax loss for 1999 was $7.1 million, of which SmartEnergy's share is $5.3 million. HSS began a test rollout through Sam's Club in late spring 1999. After a successful test market, the national rollout anticipated for year 2000 was accelerated to begin at the end of 1999. In December 1999 HSS announced that it had developed another marketing relationship with TruServ Corporation, the cooperative entity for True Value Hardware Stores. A nationwide rollout in the TruServ family of businesses will begin in 2000. HSS is seeking equity investors to finance this national rollout. As of December 31, 1999, SmartEnergy has a net investment of $2.1 million. 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 automatically passed on to consumers through rate adjustment clauses. The Company intends to continue its practice of periodically reviewing costs and requesting rate increases when warranted. Vermont 1998 Retail Rate Case: On June 12, 1998, the Company filed with the PSB for a 10.7% retail rate increase to be effective March 1, 1999. This rate case proceeding supplanted the 6.6% rate increase request referenced below that is now stayed pending a review on the so-called preclusion issue by the VSC. On October 27, 1998, the Company reached an agreement with the DPS regarding the 10.7% rate increase request. The agreement, which was approved by the PSB on December 11, 1998, provides for a temporary rate increase in the Company's Vermont retail rates of 4.7% or $10.9 million on an annualized basis beginning with service rendered January 1, 1999 and sets the Company's authorized return on equity in its Vermont retail business at 11% before disallowances in connection with the Hydro-Quebec Contract. The 4.7% rate increase is subject to retroactive or prospective adjustment upon future resolution of issues arising under the VJO Power Contract presently before the VSC. The agreement temporarily disallows approximately $7.4 million for the Company's purchased power costs under the VJO Power Contract pending resolution of the issues before the VSC. As a result of the 4.7% rate increase agreement, during the fourth quarter of 1998 and 1999, the Company recorded pre-tax losses of $7.4 million and $2.9 million for disallowed purchased power costs, representing the Company's estimated under-recovery of power costs, prior to further resolution, under the VJO Power Contract for calendar year 1999 and the first quarter of year 2000, respectively. If in the future, the Company is unable to increase rates to recover the temporary disallowed purchased power costs prior, to further resolution, under the VJO power contract or otherwise mitigate these costs, the Company would be required to record losses for any estimated future under recovery. At this time, the Company does not believe that such a loss is probable. These temporary disallowances were calculated using comparable methodology to that used by the PSB in the GMP rate case on February 28, 1998. In that case, the PSB found GMP's decision to commit to the VJO Power Contract in 1991 "imprudent" and that power purchased under it was not "used and useful." As a result, the PSB concluded that a portion of GMP's current costs should not be imposed on GMP's customers and were disallowed. GMP is appealing that rate order to the Vermont Supreme Court. Should the Company receive a similar order from the PSB, the Company would experience a material adverse effect on its results of operations and financial condition. Assuming an unfavorable VSC ruling and depending on the methodology used to determine the amount of any permanent disallowance, its future impact could be more or less than the 1999 $7.4 million temporary disallowance or the $2.9 million first quarter 2000 temporary disallowance. If the Company receives an unfavorable ruling from the VSC and the PSB subsequently issues a final rate order adopting the disallowance methodology used to determine the temporary Hydro-Quebec disallowance described above for the duration of the VJO Power Contract, the Company would not be able to recover approximately $198.2 million of power costs over the life of the contract, including $11.5 million in 2000, $11.6 million in 2001, $11.8 million in 2002, $11.9 in million 2003 and $12.1 million in 2004. In such an event, the Company would be required to take an immediate charge to earnings of approximately $198.2 million (pre-tax). Such an outcome could jeopardize the ability of the Company to continue as a going concern. 1997 Retail Rate Case: On September 22, 1997, the Company filed for a 6.6% or $15.4 million general rate increase to become effective June 6, 1998 to offset the increasing cost of providing service. $14.3 million or 92.9% of the rate increase request was to recover contractual increases in the cost of power the Company purchases from Hydro-Quebec. At the same time, the Company also filed a request to eliminate the then current differential between the rates charged customers in the summer and the rates charged customers in the winter and price electricity the same year-round. The change would be revenue-neutral within classes of customers and overall. Over time, customers would see a leveling off of rates so they would pay the same per kilowatt-hour during the winter and summer months. In response to the Company's filing, the PSB decided to appoint an independent investigator to examine the Company's decision to buy power from Hydro-Quebec. The Company made a filing with the PSB stating that the PSB as well as other parties should be barred from reviewing past decisions because the PSB already examined the Company's decision to buy power from Hydro-Quebec in a 1994 rate case in which the Company was penalized for "improvident power supply management." During February 1998, the DPS filed testimony in opposition to the Company's retail rate increase request. The DPS recommended that the PSB instead reduce the Company's then current retail rates by 2.5% or $5.7 million. The Company sought, and the PSB granted, permission to stay this rate case and to file an interlocutory appeal of the PSB's denial of the Company's motion to preclude a re-examination of the Company's Hydro-Quebec contract in 1991. The Company has argued its position before the VSC. The VSC has not yet rendered a decision and it is uncertain at this time when a decision is forthcoming. On February 28, 1998 the PSB issued an Order in a GMP rate case. That Order found GMP's decision to lock-in the Hydro-Quebec VJO contract in 1991 imprudent and further found that the contract was not used and useful. As such, the PSB concluded that a large portion of the contract's current costs should not be imposed on GMP's consumers and were disallowed. GMP appealed this rate order to the VSC. The Company is one of the participants in the Hydro-Quebec VJO contract. If the Company were to eventually receive a rate order that would result in disallowance of Hydro-Quebec power costs on a permanent basis similar to that contained in the GMP February 28, 1998 rate order, the Company's ability to continue as a going concern could be jeopardized. Because of these risks and because the PSB rejected the Company's claim that the PSB was precluded from again trying the Company on certain Hydro-Quebec and related C&LM issues, the Company concluded that it was necessary to have the so-called preclusion issue reviewed by the VSC before the PSB issues a final order in the Company's 6.6% rate increase request. Refer to Note 13 to the Consolidated Financial Statements for related information. New Hampshire 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 ("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 November 26, 1997, Connecticut Valley filed a request with the NHPUC to increase FAC, PPCA and short-term energy purchase rates effective on or after January 1, 1998. The requested increase in rates resulted from higher forecast energy and capacity charges on power Connecticut Valley purchases from the Company plus removal of a credit effective during 1997 to refund over collections from 1996. In an Order dated December 31, 1997 in Connecticut Valley's FAC and PPCA docket, the NHPUC found Connecticut Valley acted imprudently by not terminating the wholesale contract between Connecticut Valley and the Company, notwithstanding the stays of its February 28, 1997 Orders. The NHPUC Order further directed Connecticut Valley to freeze its current FAC and PPCA rates (other than short term rates to be paid to certain Qualifying Facilities) effective January 1, 1998, on a temporary basis, pending a hearing to determine: 1) the appropriate proxy for a market price that Connecticut Valley could have obtained if it had terminated its wholesale contract with the Company; 2) the implications of allowing Connecticut Valley to pass on to its customers only that market price; and 3) whether the NHPUC's final determination on the FAC and PPCA rates should be reconciled back to January 1, 1998 or some other date. See Electric Industry Restructuring discussed below and Note 13 to the Consolidated Financial Statements for additional information. On April 9, 1998 the Court issued a preliminary injunction against the NHPUC and directed and required the NHPUC to allow Connecticut Valley to recover through retail rates all costs for wholesale power requirements service that Connecticut Valley purchases from the Company pursuant to its FERC-authorized wholesale rate schedule effective January 1, 1998 until further court order. Connecticut Valley received an order from the NHPUC authorizing retail rates to recover such costs beginning in May 1998. On November 24, 1998, Connecticut Valley filed with the NHPUC its annual FAC/PPCA rates to be effective January 1, 1999. On January 4, 1999, the NHPUC issued an Order allowing Connecticut Valley to implement the proposed FAC rate of $.008 per KWH and the proposed PPCA rate of $.01000 per KWH, on a temporary basis, effective on all bills rendered on or after January 1, 1999. In addition, the NHPUC also ordered Connecticut Valley to pay refunds plus interest to its retail customers for any overcharges collected as a result of the April 9, 1998 Federal District Court Order, should it be overturned or modified. As a result of the December 3, 1998 Court of Appeals' decision, see New Hampshire Retail Rates/Federal Court Proceedings below, on March 22, 1999, the NHPUC issued an Order which directed Connecticut Valley to file within five business days its calculation of the difference between the total FAC and the PPCA revenues that it would have collected had the 1997 FAC and PPCA rate levels been in effect the entire year. In its Order, the NHPUC also directed Connecticut Valley to calculate a rate reduction to be applied to all billings for the period April 1, 1999 through December 31, 1999 to refund the 1998 over collection relative to the 1997 rate level. The Company estimated this amount to be approximately $2.7 million on a pre-tax basis. Connecticut Valley filed the required tariff page with the NHPUC, under protest and with reservation of all rights, on March 26, 1999 and implemented this refund effective April 1, 1999. On April 7, 1999, the Court ruled from the bench that the March 22, 1999 NHPUC Order requiring Connecticut Valley to provide a refund to its retail customers was illegal and beyond the NHPUC's authority. The Court also ruled that the NHPUC cannot reduce Connecticut Valley's rates below rates in effect at December 31, 1997. Accordingly, Connecticut Valley removed the rate refund from retail rates effective April 16, 1999. The NHPUC held a hearing on April 22, 1999 to determine whether to modify Connecticut Valley's 1999 power rates by returning the rates to the levels that were in effect on December 31, 1997. On May 17, 1999, the NHPUC issued an order requiring Connecticut Valley to set temporary rates at the level in effect as of December 31, 1997, subject to future reconciliation effective with bills issued on and after June 1, 1999. On December 1, 1999, Connecticut Valley filed with the NHPUC a petition for a change in its FAC and PPCA rates effective on bills rendered on and after January 1, 2000. On December 30, 1999, the NHPUC denied Connecticut Valley's request to increase its FAC and PPCA rates above those in effect at December 31, 1997 subject to further investigation and reconciliation until otherwise ordered by the NHPUC. Proposed Formation of Holding Company In order to further prepare Central Vermont Public Service Corporation for deregulation, on July 24, 1998, the Company filed a petition with the PSB for permission to create a holding company that would have as subsidiaries the Company and non-utility subsidiaries, Catamount and SmartEnergy. The Company believes that a holding company structure will facilitate the Company's transition to a deregulated electricity market. The proposed holding company formation must also be approved by Federal regulators, including the Securities and Exchange Commission and the FERC, and by the Company's shareholders. Year 2000 Information Systems Modifications The Company experienced no failures or business interruptions as a result of the transition from December 31, 1999 to January 1, 2000 and for the transition of the leap year date from February 28, 2000 to February 29, 2000. To date, the Company has also been successful with all transactions with its principal power and transmission suppliers as well as other vendors and suppliers, and does not anticipate any problems will surface in the future. The Company is part of the Northeast grid contingency plan to provide electricity to its customers on a priority basis in the event of power outages. The Company also has other contingency plans developed in the event of the failure of its transmission, generation, distribution, metering, telecommunications, information and public communications systems. As previously estimated, the Company has incurred $4.0 million to date to make the necessary modifications to its computer systems and for its contingency plans. In accordance with a PSB Accounting Order, the Company has deferred a portion of these costs which will be amortized over a five-year period beginning January 1, 2000. Per PSB Order dated December 11, 1998, the Company is authorized to seek recovery of these costs through future regulatory proceedings. ELECTRIC INDUSTRY RESTRUCTURING The electric utility industry is in a period of transition that may result in a shift away from rate making based on cost of service and return on equity to more market-based rates with energy sold to customers by competing retail energy service providers. Many states, including Vermont and New Hampshire, where the Company does business, are exploring new mechanisms to bring greater competition, customer choice and market influence to the industry while retaining the public benefits associated with the current regulatory system. Vermont Recently, there have been three primary sources of Vermont governmental activity in attempting to restructure the electric industry in Vermont: (1) the Governor's Working Group, created by the Governor of Vermont; (2) the PSB's Docket No. 6140, through which the PSB considered restructuring proposals; (3) the PSB's Docket No. 6330, through which the PSB is considering the establishment of policies and procedures to govern retail competition with the Company's service territory. The Working Group On July 22, 1998, the Governor of Vermont issued an Executive Order establishing the Working Group on Vermont's Electricity Future to lead a new effort to review the issues of potential restructuring of Vermont's electric industry. The Working Group was created to determine how restructuring the electric industry in Vermont could reduce both current and long-term electric costs for all classes of Vermont electric consumers. The Working Group was asked to provide a fact-based analysis of the options for electric industry restructuring and the impact of such industry changes on consumers and upon Vermont utilities. Further, the Working Group was directed by the Governor of Vermont to gather information on and evaluate the possible consequences of the current financial status of Vermont electric utilities. A report was issued by the Working Group on December 18, 1998. Key conclusions of its report were: - The bankruptcy of Vermont electric utilities should not be viewed as an appropriate means to reduce Vermont utilities' above-market power supply costs. - Vermont should restructure its electric industry by moving rapidly to retail choice whereby consumers would purchase power directly from competing power suppliers. - Vermont electric utilities should pursue power contract renegotiations through payments to buy down power contracts or buy-out power contracts. Financing for such payments should be obtained in the capital markets after a comprehensive regulatory process dealing with all of the elements of the restructuring of the Vermont electric utility industry. - The Vermont electric utilities should pursue auctions of their power generation assets and remaining power contracts. - Consolidation of existing electric utilities in Vermont (there are currently 22 utilities) should be considered in order to effect additional savings for utility customers. The Working Group noted that by March 1, 2000, most New Englanders outside Vermont will have a choice of their power supplier. While New England has the highest electricity rates in the nation, electricity costs in Vermont have been among the lowest in the region, although our rates are higher than the Vermont average. However, that advantage is eroding as other states in New England restructure their electric utility industries. Therefore, the Working Group noted that it is in the interest of Vermont ratepayers to have the benefit of a restructured electric utility industry as soon as possible. Public Service Board Docket No. 6140 On September 15, 1998, the PSB opened a formal proceeding in Docket No. 6140 with the goal of creating a regulatory environment and a procedural framework to call forth, for disciplined review, proposals for reducing current and future power costs in Vermont. The PSB intended that this proceeding would define one or more acceptable courses for reform. All Vermont utilities were made a party to that proceeding. Subsequent to the PSB's announcement, preliminary position papers were filed and a series of technical conferences were convened with the PSB to recommend the scope of the investigation, potential courses for reform of Vermont's power supply and other matters associated therewith including the consideration of the Working Group's recommendations. On March 3, 1999, the Company filed its Restructuring Plan, a Working Plan to restructure a significant portion of Vermont's Electric Utility Industry, with the PSB and parties in Docket No. 6140. The Company's plan was a joint plan with GMP. On July 12, 1999, the PSB issued a Status Order concluding that the objective of implementing power supply reform may be advanced more effectively in ways other than holding further technical conferences in this docket. Absent good reason to hold one or more technical conferences pertinent to power supply reform, the PSB indicated that the docket would be closed on December 31, 1999, which action has occurred. As a companion proceeding to its investigation in Docket No. 6140, on January 19, 1999, the PSB issued an order opening a new contested case proceeding, Docket No. 6140-A, where it indicated that it intended to issue final, binding and appealable orders concerning matters related to the reform and restructuring of Vermont's electric utility industry. Initially, the PSB notified parties that it intended proceedings in Docket No. 6140-A to consider matters associated with the bankruptcy of one or more of the Vermont electric utilities. After an opportunity for comment, the focus of the proceeding was amended to first consider the principles, authority and proposals for reform of Vermont's electric power supply. This includes issues associated with the scope and extent of the Board's authority to approve "securitization" and other financings proposed to be entered into in connection with the buy-out or buy-down of power contracts and the criteria to be applied by the PSB when considering voluntary utility restructuring proposals. By Order dated June 24, 1999 in Docket 6140-A, the PSB formally adopted the Vermont Principles on Electric Utility Restructuring. The Order explains that proposals to open utility franchise service areas to retail competition, including our Restructuring Plan, will only be approved if they can be found to satisfy the public good after due consideration is given to each of 14 Restructuring Principles. If one or more of the principles is not satisfied by the proposal, then the proponent must offer justification for the deficiency and demonstrate satisfaction of certain statutory requirements. As such, the PSB stated that any filing proposing to open a franchise territory to retail choice would have to be supported, at a minimum, by an explanation of how that proposal fulfills the policy objectives established by the Vermont Principles on Electric Utility Restructuring. With regard to financing, no party to the investigation asked that the PSB clarify its authority or issue a declaratory ruling concerning the criteria to be considered when approving utility financings for the buy-out or buy-down of committed power contracts. During the investigation, both the Company and Green Mountain Power Corporation asserted that anticipated refinancing approaches could be accomplished utilizing the existing Vermont and federal legislative regime that governs the regulation of electric utilities and that "securitization" style financings were not presently being contemplated. Because no party to the Docket contradicted these statements, the Board accepted our assertions and took no further action to evaluate specific utility financing proposals. In contrast, Vermont Electric Power Producers, Inc.("VEPP"), purchasing agent for the purchase of power from qualifying facilities pursuant to PSB Rule 4.100, proposed to use administrative securitization to finance the reform of its power purchase contracts. However, at the request of all commenting parties, the PSB determined to withhold judgment on the issue as to whether the PSB had jurisdiction to authorize a VEPP financing until such time as a specific proposal was actually filed with the PSB. Toward this end, the PSB has stated that it will convene a workshop, independent of this Docket, to further discuss VEPP's financing proposal and to prepare for the opening of a possible rulemaking proceeding to amend Rule 4.100 on this topic. In the absence of any requests for further investigation or action to be filed within 30 days of the Docket No. 6140-A Order, the PSB indicated that this investigation would be closed, which action has occurred. The Company supports the Working Group recommendations described above and believes that the restructuring of the electric industry is essential to improve our financial position, enhance our ability to effectively compete in a changing electric utility industry and stabilize projected costs. As a result, the Company is pursuing a comprehensive financial Restructuring Plan, certain elements of which were included in a report that the Company and GMP filed with the PSB in the first quarter of 1999 in connection with the proceedings in Docket No. 6140 described above. The Company is aggressively pursuing implementation of the Restructuring Plan which includes the following elements: - Retail choice: voluntarily giving up the exclusive right to supply power to the Company's present electric customers, while retaining its rights as a distribution company, as part of a global settlement of regulatory issues. - Renegotiation of certain purchase power contracts: reducing the Company's future cost of power by renegotiating power contracts, specifically those with Hydro-Quebec and the Vermont purchasing agent's contracts with IPPs which together represent approximately 40% of the Company's 1998 net energy supply. The Company may seek to finance the cost of any buy-outs or buy-downs of power contracts through the future issuance of securities in the capital markets. - Contract and asset disposition: seeking to sell power purchase contracts and generating assets, including the interest in the Vermont Yankee nuclear generating plant. On October 15, 1999, the Company and the other owners of Vermont Yankee accepted a bid for sale of the plant to AmerGen Energy Company, which is owned by PECO Energy Company and British Energy. This transaction will also involve taking back a contract to purchase a portion of the power produced by this plant. The Vermont Yankee sale needs to be approved by numerous state and federal regulatory bodies. On November 4, 1999 the PSB opened Docket No. 6300 to consider the issues attendant to the approval of the sale of Vermont Yankee and approval of various related agreements including the Company's agreement to continue to purchase its share of the output of Vermont Yankee. - Cost-cutting: implementing cost-cutting measures to reduce cash flow requirements while maintaining safety and reliability standards. - Holding company: establishing a holding company in order to further prepare the Company for deregulation. - Industry consolidation: evaluating possible consolidation with other Vermont electric distribution companies. - Regulatory settlement: seeking a comprehensive regulatory settlement that leads to long-term financial stability. - Energy efficiency activities: creating a state sponsored "energy-efficiency utility" to take over most system-wide energy-efficiency services for electric customers. On September 30, 1999, the PSB issued a final Order approving a Memorandum of Understanding between the Company, the Vermont Department of Public Service, all other Vermont electric utility companies and other interested parties that calls for the establishment of the energy-efficiency utility and provides for its funding via a separate stated Energy Efficiency Charge. The Company believes that implementation of its Restructuring Plan is a critical element to improving its future financial performance and to providing its customers with more stable electric rates and the continuation of efficient and reliable electric service. The key contingency of the Company's Restructuring Plan is regulatory approval of a rate schedule that will allow the Company to recover the costs of the restructuring. If the financial restructuring described in this section is completed in conjunction with the deregulation of Vermont's electric industry described in "Electric Industry Restructuring," the Company anticipates that its utility financial performance and prospects will improve significantly. Public Service Board Docket No. 6330 On November 23, 1999, the Company and GMP or the Companies filed a joint Petition and Supporting Materials with the PSB asking that the PSB open an investigation to establish retail access policies and procedures to resolve issues that must be decided to implement the Companies' Restructuring Plan. Specifically, the Petition requests that the PSB issue such orders and approvals as are necessary or advisable to: 1) permit the Companies to suspend their provision of power supply Services, or Generation Service to customers located within their service territories; 2) permit the Companies to amend their service tariff obligations to clarify that they retain their exclusive service franchises as providers of electric delivery services, or Delivery Service to customers within their respective service territories; 3) permit the Companies to implement a Retail Open Access Tariff, or "R-OAT" that enables customers located within the Companies' respective service territories to choose their power supplier from an array of approved energy service providers ("ESP"), and to purchase Generation Service from such ESPs at market-determined prices; 4) select through a competitive bidding process an ESP or ESPs to deliver "Default Service" for energy to customers located within the Companies' service territories; 5) select through a competitive bidding process an ESP or ESPs to deliver "Transition Service" for energy to customers located within the Companies' service territories; and 6) approve revisions and modifications to the Companies' tariffs to implement voluntary retail access within the Companies' respective service territories as provided for pursuant to this Petition. The consent to retail access within the Companies' service areas established by the Petition is voluntary and conditional. Pursuant to the Petition, the Company's' consent to customer choice and retail competition is expressly conditioned upon approval of all elements of the Companies' Restructuring Plan including the approval of any proposed mitigation measures to reduce power costs and financing measures related thereto, and a mechanism to recover the costs rendered stranded on account of the move to retail access and customer choice. On January 14, 2000, the PSB opened Docket No. 6330 to consider the issues raised by the Companies' petition. In its opening Order, the Board states: "The scope of this investigation is intended to address many of the more detailed aspects of retail open access. While current law may not permit this Board to require retail open access of Vermont utilities, the companies are clearly able to open their service territories on a voluntary basis. Whether retail open access is established on a voluntary basis through existing statutes or through revised legislation, there are many technical issues to be resolved. This investigation will serve to advance many aspects of issues surrounding retail open access." An initial pre-hearing conference was held in this investigation on January 31, 2000. At this time, it is premature to predict the date upon which a final PSB resolution of the matters raised in this investigation will be decided although, the Companies proposed an initial start date for retail competition of September 1, 2001, provided that all of the elements of the joint Restructuring Plan are completed by that time. New Hampshire Retail Rates/Federal Court Proceedings On February 28, 1997 the NHPUC published its detailed Final Plan to restructure the electric utility industry in New Hampshire. Also on February 28, 1997, the NHPUC, in a supplemental order specific to Connecticut Valley, found that Connecticut Valley was imprudent for not terminating the FERC-authorized power contract between Connecticut Valley and the Company, required Connecticut Valley to give notice to cancel its contract with the Company and denied stranded cost recovery related to this power contract. Connecticut Valley filed for rehearing of the February 28, 1997 NHPUC Order. On April 7, 1997, the NHPUC issued an Order addressing certain threshold procedural matters raised in motions for rehearing and/or clarification filed by various parties, including Connecticut Valley, relative to the Final Plan and interim stranded cost orders. The April 7, 1997 Order stayed those aspects of the Final Plan that were the subject of rehearing or clarification requests and also stayed the interim stranded cost orders for the various parties, including Connecticut Valley. As such, those matters pertaining to the power contract between Connecticut Valley and the Company were stayed. The suspension of these orders was to remain in effect until two weeks following the issuance of any order concerning outstanding requests for rehearing and clarification. On November 17, 1997, the City of Claremont, New Hampshire ("Claremont"), filed with the NHPUC a petition for a reduction in Connecticut Valley's electric rates. Claremont based its request on the NHPUC's earlier finding that Connecticut Valley's failure to terminate its wholesale power contract with the Company as ordered in the NHPUC Stranded Cost Order of February 28, 1997 was imprudent. Claremont alleged that if Connecticut Valley had given written notice of termination to the Company in 1996 when legislation to restructure the electric industry was enacted in New Hampshire, Connecticut Valley's obligation to purchase power from the Company would have terminated as of January 1, 1998. On November 26, 1997, Connecticut Valley filed a request with the NHPUC to increase the FAC, PPCA and short-term energy purchase rates effective on or after January 1, 1998. The requested increase in rates resulted from higher forecast energy and capacity charges on power Connecticut Valley purchases from the Company plus removal of a credit effective during 1997 to refund over collections from 1996. Connecticut Valley objected to the NHPUC's notice of intent to consolidate Claremont's petition into the FAC and PPCA docket, stating that Claremont's complaint should be heard as part of the NHPUC restructuring docket. Over Connecticut Valley's objection at the hearing on December 17, 1997, the NHPUC consolidated Claremont's petition with Connecticut Valley's FAC and PPCA proceeding. In an Order dated December 31, 1997 in Connecticut Valley's FAC and PPCA docket, the NHPUC found Connecticut Valley acted imprudently by not terminating the wholesale contract between Connecticut Valley and the Company, notwithstanding the stays of its February 28, 1997 Orders. The NHPUC Order further directed Connecticut Valley to freeze its current FAC and PPCA rates (other than short term rates to be paid to certain Qualifying Facilities) effective January 1, 1998, on a temporary basis, pending a hearing to determine: 1) the appropriate proxy for a market price that Connecticut Valley could have obtained if it had terminated its wholesale contract with the Company; 2) the implications of allowing Connecticut Valley to pass on to its customers only that market price; and 3) whether the NHPUC's final determination on the FAC and PPCA rates should be reconciled back to January 1, 1998 or some other date. On January 19, 1998, Connecticut Valley and the Company filed with the Court for a temporary restraining order to maintain the status quo ante by staying the December 31, 1997 NHPUC Order and preventing the NHPUC from taking any action that (i) compromises cost-based rate making for Connecticut Valley or otherwise seeks to impose market price-based rate making on Connecticut Valley; (ii) interferes with the FERC's exclusive jurisdiction over the Company's pending application to recover wholesale stranded costs upon termination of its wholesale power contract with Connecticut Valley; or (iii) prevents Connecticut Valley from recovering through retail rates the stranded costs and purchased power costs that it incurs pursuant to its FERC-authorized wholesale rate schedule with the Company. On February 23, 1998, the NHPUC announced in a public meeting that it reaffirmed its finding of imprudence and designated a proxy market price for power at 4 cents per kWh in lieu of the actual costs incurred pursuant to the wholesale power contract with the Company. In addition, the NHPUC indicated, subject to certain conditions which were unacceptable to the companies, that it would permit Connecticut Valley to maintain its current rates pending a decision in Connecticut Valley's appeal of the NHPUC Order to the New Hampshire Supreme Court. Based on the December 31, 1997 NHPUC Order as well as the NHPUC's February 23, 1998 announcement, which resulted in the establishment of Connecticut Valley's rates on a non cost-of-service basis, Connecticut Valley no longer qualified, as of December 31, 1997, for the application of SFAS No. 71. As a result, Connecticut Valley wrote-off all of its regulatory assets associated with its New Hampshire retail business as of December 31, 1997. This write-off amounted to $1.2 million on a pre-tax basis. In addition, Connecticut Valley recorded a $5.5 million pre-tax loss in 1997 for disallowed power costs. On March 20, 1998, the NHPUC issued an order which affirmed, clarified and modified various generic policy statements including the reaffirmation to establish rates on the basis of a regional average announced previously in its February 28, 1997 Final Plan. The March 20, 1998 order also addressed all outstanding motions for rehearings or clarification relative to the policies or legal positions articulated in the Final Plan and removed the stay covering the Company's interim stranded cost order of April 7, 1997. In addition, the March 20, 1998 Order imposed various compliance filing requirements. On April 3, 1998, the Court held a hearing on the Companies' motion for a Temporary Restraining Order, or TRO, and Preliminary Injunction against the NHPUC at which time both the Companies and the NHPUC presented arguments. In an oral ruling from the bench, and in a written order issued on April 9, 1998, the Court concluded that the Companies had established each of the prerequisites for preliminary injunctive relief and directed and required the NHPUC to allow Connecticut Valley to recover through retail rates all costs for wholesale power requirements service that Connecticut Valley purchases from the Company pursuant to its FERC-authorized wholesale rate schedule effective January 1, 1998 until further court order. Connecticut Valley received an order from the NHPUC authorizing retail rates to recover such costs beginning in May 1998. On April 14, 1998, the NHPUC filed a notice of appeal and a motion for a stay of the Court's preliminary injunction. The NHPUC's request for a stay was denied. At the same time, the NHPUC permitted Connecticut Valley to recover in rates the full cost of its wholesale power purchases from the Company. Also, on April 3, 1998, the Court indicated that its earlier TRO enjoining the NHPUC's restructuring orders applied to Connecticut Valley and prohibits the enforcement of the restructuring orders until the Court conducts a consolidated hearing and rules on the requests for permanent injunctive relief by plaintiff PSNH and the other utilities that had been allowed to intervene in these proceedings, including the Company and Connecticut Valley. The plaintiffs-intervenors thereafter filed a motion asking the Court to extend its stay of action by the NHPUC to implement restructuring and to make clear that the stay encompasses the NHPUC's order of March 20, 1998. As a result of these Court orders, Connecticut Valley's 1997 charges described above were reversed in the first quarter of 1998. Combined, the reversal of these charges increased first quarter 1998 net income and earnings per share of common stock by $4.5 million and $.39, respectively. On April 1, 1998, Citizens Bank of New Hampshire, or Bank, notified Connecticut Valley that it was in default of the Loan Agreement between the Bank and Connecticut Valley dated December 27, 1994 and that the Bank would exercise all of its remedies from and after May 5, 1998 in the event that the violations were not cured. After reversing the 1997 write-offs described above, Connecticut Valley was in compliance with the financial covenants associated with its $3.75 million loan with the Bank. As a result, Connecticut Valley satisfied the Bank's requirements for curing the violation. On May 11, 1998 the NHPUC issued an order requiring Connecticut Valley to show cause why it should not be held in contempt for its failure to meet the compliance filing requirements of its March 20, 1998 Order. A hearing on this matter was scheduled for June 11, 1998, which was subsequently canceled because of the Court's June 5, 1998 Order, discussed below. On June 5, 1998, the Court issued an Order which denied the NHPUC's motion for a stay of the Court's preliminary injunction. The Order clearly states that no restructuring effort in New Hampshire can move forward without the Court's approval unless all New Hampshire utilities agree to the plan. The Order suspended all involuntary restructuring efforts for all New Hampshire utilities until a hearing is conducted. The NHPUC appealed this Order to the United States First Circuit Court of Appeals ("Court of Appeals"). On July 23, 1998, the NHPUC issued an order vacating that portion of its February 27, 1997 restructuring order that had directed Connecticut Valley to terminate its RS-2 wholesale power purchases from the Company. The NHPUC has expressly stated in federal court filings that its July 23, 1998 order "clarified that Connecticut Valley should not terminate the RS-2 Rate Schedule if such termination would trigger the exit fee" for which the Company has sought authorization from FERC. On November 24, 1998, Connecticut Valley filed with the NHPUC its annual FAC/PPCA rates to be effective January 1, 1999. On January 4, 1999, the NHPUC issued an Order allowing Connecticut Valley to implement the proposed FAC rate of $.008 per KWH and the proposed PPCA rate of $.01000 per KWH rate on a temporary basis, effective on all bills rendered on or after January 1, 1999. In addition, the NHPUC also ordered Connecticut Valley to pay refunds plus interest to its retail customers for any overcharges collected as a result of the April 9, 1998 Court Order should it be overturned or modified, which are included in the estimated total losses of $4.3 million discussed below. On December 3, 1998, the Court of Appeals announced its decisions on the appeals taken by the NHPUC from the preliminary injunctions issued by the Court. Those preliminary injunctions had stayed implementation of the NHPUC's plan to restructure the New Hampshire electric industry and required the NHPUC to allow Connecticut Valley to recover through its retail rates the full cost of wholesale power obtained from the Company. The Court of Appeals affirmed the preliminary injunction, issued by the Court, staying restructuring until the plaintiff utilities' claims (including those of the Company and Connecticut Valley) are fully tried. The Court of Appeals found that PSNH had sufficiently established that without the preliminary injunction against restructuring it would suffer substantial irreparable injury and that it had sufficient claims against restructuring to warrant a full trial. The Court of Appeals also affirmed the extension of the preliminary injunction to protect the other plaintiff utilities, including Connecticut Valley and the Company, although it questioned whether the other utilities had arguments as strong against restructuring as PSNH because they did not have formal agreements with the State similar to PSNH's Rate Agreement. The Court of Appeals stated that if the Court awards the utilities permanent injunctive relief against restructuring after the case is tried, then it must explain why the other utilities are also entitled to such relief. The NHPUC filed a petition for rehearing on December 17, 1998. The Court of Appeals denied the petition on January 13, 1999. The Court of Appeals also reversed the Court's preliminary injunction requiring the NHPUC to allow Connecticut Valley to recover in retail rates the full cost of the power it buys from the Company. Although the Court of Appeals found that Connecticut Valley and the Company had made a strong showing of irreparable injury to justify the preliminary injunction, it concluded that Connecticut Valley's and the Company's claims did not have a sufficient probability of success to warrant such preliminary relief. The Court of Appeals explained that the filed-rate doctrine preserving the exclusive jurisdiction of the FERC over wholesale power rates did not prevent the NHPUC from deciding whether Connecticut Valley's power purchases from the Company were prudent given alternative available sources of wholesale power. The Court of Appeals then stated that Connecticut Valley's rates could be reduced to the level prevailing on December 31, 1997. However, the Court of Appeals also stated that if the NHPUC ordered Connecticut Valley's rates to be reduced below the level existing as of December 31, 1997, "it will be time enough to consider whether they are precluded from the Court's injunction against the Final Plan or on other grounds." On December 17, 1998, Connecticut Valley and the Company filed a petition for rehearing on the grounds that the Court of Appeals had not given sufficient weight to the Court's factual findings and that the Court of Appeals had misapprehended both factual and legal issues. Connecticut Valley and the Company also asked that the entire Court of Appeals, rather than only the three-judge appellate panel that had issued the December 3 decision, consider their petition for rehearing. On January 13, 1999, the Court denied the petition for rehearing. Connecticut Valley and the Company then requested the Court of Appeals to stay the issuance of its mandate until the companies could file a petition for certiorari to the United States Supreme Court and the Supreme Court acted on the petition. On January 22, 1999, the Court of Appeals denied the request. However, the Court of Appeals granted a 21-day stay to enable the Company to seek a stay pending certiorari from the Circuit Justice of the Supreme Court. On February 11, 1999, the Company and Connecticut Valley filed a petition for a writ of certiorari with the United States Supreme Court and a motion to stay the effect of the Court of Appeals' decision while the case was pending in the Supreme Court. The motion for a stay was addressed to Justice Souter who is responsible for such motions pertaining to the Court of Appeals for the First Circuit. On February 18, 1999, Justice Souter denied the stay pending the petition for certiorari. On April 19, 1999, the Supreme Court denied the petition for certiorari. As a result of the December 3, 1998 Court of Appeals' decision discussed above, on March 22, 1999, the NHPUC issued an Order which directed Connecticut Valley to file within five business days its calculation of the difference between the total FAC and PPCA revenues that it would have collected had the 1997 FAC and PPCA rate levels been in effect the entire year. In its Order, the NHPUC also directed Connecticut Valley to calculate a rate reduction to be applied to all billings for the period April 1, 1999 through December 31, 1999 to refund the 1998 over collection relative to the 1997 rate level. The Company estimated this amount to be approximately $2.7 million on a pre-tax basis. Connecticut Valley filed the required tariff page with the NHPUC, under protest and with reservation of all rights, on March 26, 1999 and implemented the refund effective April 1, 1999. As a result of legal and regulatory actions discussed above, Connecticut Valley no longer qualified as of December 31, 1998 for the application of SFAS No. 71, and wrote-off in the fourth quarter of 1998 all its regulatory assets associated with its New Hampshire retail business estimated at approximately $1.3 million on a pre-tax basis at December 31, 1998. In addition, Connecticut Valley recorded estimated total losses of $4.3 million pre-tax during the fourth quarter of 1998 for disallowed power costs of $1.6 million and its refund obligations of $2.7 million. Company management, however, continues to believe that the NHPUC's actions are illegal and unconstitutional and will present its arguments in the appropriate forum. The pre-tax losses described above resulted in Connecticut Valley violating applicable covenants, which if not waived or renegotiated, would have allowed Connecticut Valley's lender the right to accelerate the repayment of a $3.75 million loan with Connecticut Valley. On March 12, 1999, Connecticut Valley was notified by the Bank that it would exercise appropriate remedies in connection with the violation of financial covenants associated with the $3.75 million loan agreement unless the violation was cured by April 11, 1999. To avoid default of this loan agreement, on April 6, 1999, pursuant to an agreement reached on March 26, 1999, the Company purchased from the Bank the $3.75 million note. On April 7, 1999, the Court ruled from the bench that the March 22, 1999 NHPUC Order requiring Connecticut Valley to provide a refund to its retail customers was illegal and beyond the NHPUC's authority. The Court also ruled that the NHPUC cannot reduce Connecticut Valley's rates below rates in effect at December 31, 1997. Accordingly, Connecticut Valley removed the rate refund from retail rates effective April 16, 1999. Lastly, the Court denied the NHPUC's motion to dissolve the injunction staying the implementation of its restructuring plan and stated its desire to rule on the pending motion for summary judgement and to conduct a hearing on the Company's request for a permanent injunction, after the NHPUC completes hearings on PSNH's stranded costs. The District Court's decision was issued as a written order on May 11, 1999. The NHPUC held a hearing on April 22, 1999 to determine whether to modify Connecticut Valley's 1999 power rates by returning the rates to the levels that were in effect on December 31, 1997. On May 17, 1999, the NHPUC issued an order requiring Connecticut Valley to set temporary rates at the level in effect as of December 31, 1997, subject to future reconciliation, effective with bills issued on and after June 1, 1999. On May 24, 1999, the NHPUC filed a petition for mandamus in the Court of Appeals challenging the Court's May 11, 1999 ruling and seeking a decision allowing the refunds as required by the NHPUC's March 22, 1999 order. The Court of Appeals denied that petition on June 2, 1999. The NHPUC immediately filed a notice of appeal in the Court of Appeals again challenging the Court's May 11, 1999 ruling. In that appeal, the Company and Connecticut Valley contend, among other things, that it is unfair for the NHPUC to direct Connecticut Valley to continue to purchase wholesale power under RS-2 in order to avoid the triggering of a FERC exit fee, but at the same time to freeze Connecticut Valley's rates at their December 31, 1997 level which does not enable Connecticut Valley to recover all of its RS-2 costs. The Court of Appeals issued a decision on January 24, 2000, which upheld the Court's preliminary injunction enjoining the Commission's restructuring plan. The decision also remanded the refund issue do the Court stating: "The district court may defer vacation of this injunction against the refund order for up to 90 days. If within that period it has decided the merits of the request for a permanent injunction in a way inconsistent with refunds, or has taken any other action that provides a showing that the Company is likely to prevail on the merits in federal court in barring the refunds, it may enter a superseding injunction against the refund order, which the Commission may then appeal to us. Otherwise, no later than the end of the 90-day period, the district court must vacate its present injunction insofar as it enjoins the Commission's refund order." The parties have also submitted motions for summary judgment to the Court, which the Court has under consideration. On March 6, 2000 the Court issued a permanent injunction mandating that the NHPUC allow Connecticut Valley to pass through to its retail customers its wholesale costs incurred under the RS-2 rate schedule with the Company. The Court also ruled that Connecticut Valley is entitled to recover those wholesale costs that the NHPUC has disallowed in retail rates since January 1, 1997. This decision is subject to implementation by the NHPUC and is subject to appeal. On June 14, 1999, PSNH and various parties in New Hampshire announced that a "Memorandum of Understanding" had been reached that is intended to result in a detailed settlement proposal to the NHPUC that would resolve PSNH's claims against the NHPUC's restructuring plan. On July 6, 1999, PSNH petitioned the Court to stay its proceedings indefinitely while the proposed settlement is reviewed and approved by the NHPUC and the New Hampshire Legislature. On July 12, 1999 the Company and Connecticut Valley objected to any stay that would allow the NHPUC's rate freeze order to remain in effect for an extended period and asked the Court to proceed with prompt hearings on its summary judgement motion and trial on the merits. On October 20, 1999 the Court heard oral arguments pertaining to the pretrial motions of the Company and the NHPUC for summary judgement and dismissal, respectively. The Court took the matters under advisement and indicated that a written order would ensue. On December 1, 1999, Connecticut Valley filed with the NHPUC a petition for a change in its FAC and PPCA rates effective on bills rendered on and after January 1, 2000. On December 30, 1999, the NHPUC denied Connecticut Valley's request to increase its FAC and PPCA rates above those in effect at December 31, 1997 subject to further investigation and reconciliation until otherwise ordered by the NHPUC. Accordingly, during the fourth quarter of 1999 Connecticut Valley recorded $1.2 million for under collection of year 2000 power costs. FERC Proceedings The Company filed an application with the FERC in June 1997, to recover stranded costs in connection with its wholesale rate schedule with Connecticut Valley and a notice of cancellation of the Connecticut Valley rate schedule (contingent upon the recovery of the stranded costs that would result from the cancellation of this rate schedule). In December 1997, the FERC rejected the Company's proposal to recover stranded costs through the imposition of a surcharge on our transmission tariff, but indicated that it would consider an exit fee mechanism for collecting stranded costs. The FERC denied the Company's motion for a rehearing regarding the surcharge proposal, so the Company filed a request with the FERC for an exit fee mechanism to collect the stranded costs resulting from the cancellation of the contract with Connecticut Valley. The stranded cost obligation sought to be recovered through an exit fee, expressed on a net present value basis as of January 1, 2000, is approximately $44.9 million. During April and May 1999, nine days of hearings were held at the FERC before an Administrative Law Judge, who will determine, among other things, whether Connecticut Valley qualifies for an exit fee, and if so, the amount of Connecticut Valley's stranded cost obligation to be paid to the Company as an exit fee. The ruling of the Administrative Law Judge is expected in the first half of 2000, and the FERC will act on the judge's recommendations sometime thereafter. If the Company is unable to obtain an order authorizing the recovery of costs in connection with the June 1997 FERC filing or in the Federal Court, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $56.3 million on a pre-tax basis. The Company would also be required to write-off approximately $3.0 million (pre-tax)in regulatory assets associated with its wholesale business. However, even if the Company obtains a FERC order authorizing the updated requested exit fee, if Connecticut Valley is unable to recover its costs by increasing its rates, Connecticut Valley would be required to recognize a loss under this contract of approximately $44.9 million (pre-tax) representing future under recovery of power costs. In addition to its efforts before the Court and FERC, Connecticut Valley has initiated efforts and will continue to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC. On September 14 and 15, 1998 the Company participated in a settlement conference with an Administrative Law Judge assigned for the settlement process at the FERC and the parties to the Company's exit fee filing. An adverse resolution of these proceedings would have a material adverse effect on the Company's results of operations and cash flows. However, the Company cannot predict the ultimate outcome of this matter. For further information on New Hampshire restructuring issues and other regulatory events in New Hampshire affecting the Company or Connecticut Valley and the 1997 and 1998 charges and reversals of the 1997 charges, see the Company's Current Reports on Form 8-K dated January 12, 1998, January 28, 1998, April 1, 1998 and February 1, 1999; the Company's Form 10-Q for the quarterly periods ended March 31, June 30 and September 30, 1998; and March 31, June 30 and September 30, 1999. Also, Item 1. Business-New Hampshire Retail Rates, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Electric Industry Restructuring-New Hampshire and Item 8. Financial Statements and Supplementary Data-Note 13, Retail Rates-New Hampshire in the Company's 1998 and 1997 Annual Reports on Form 10-K. Connecticut Valley constitutes approximately 7% of the Company's total retail mWh sales. 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 with respect to their power supply purchases and attract new customers or the margins that will be realized on retail sales of electricity, if any such sales are sought. The Company expects its power distribution and transmission service to its customers to continue on an exclusive basis subject to continuing economic regulation. 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. SFAS No. 71 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 Note 1 of Notes to Consolidated Financial Statements, the Company believes it currently complies with the provisions of SFAS No. 71 for both its regulated Vermont service territory and FERC regulated wholesale businesses. 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 approximately $62.8 million on a pre-tax basis as of December 31, 1999. 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. The Securities and Exchange Commission has questioned the ability of certain utility companies continuing the application of SFAS No. 71 where legislation provides for the transition to retail competition. Deregulation of the price of electricity issues related to the application of SFAS No. 71 and 101, as to when and how to discontinue the application of SFAS No. 71 by utilities during transition to competition has been referred to the Financial Accounting Standards Board's Emerging Issues Task Force ("EITF"). The EITF has reached a tentative consensus, and no further discussion is planned, that regulatory assets should be assigned to separable portions of the Company's business based on the source of the cash flows that will recover those regulatory assets. Therefore, if the source of the cash flows is from a separable portion of the Company's business that meets the criteria to apply SFAS No. 71, those regulatory assets should not be written off under SFAS No. 101, "Accounting for the Discontinuation of Application of SFAS No. 71," but should be assessed under paragraph 9 of SFAS No. 71 for realizability. SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and for Long-Lived Assets to Be Disposed Of," which was adopted 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, 1999, 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. Because the Company is unable to predict what form possible future restructuring legislation will take, it cannot predict if or to what extent SFAS Nos. 71 and 121 will continue to be applicable in the future. In addition, if the Company is unable to mitigate or otherwise recover stranded costs that could arise from any potentially adverse legislation or regulation, the Company would have to assess the likelihood and magnitude of losses incurred under its power contract obligations. As such, the Company cannot predict whether any restructuring legislation enacted in Vermont or New Hampshire, once implemented, 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, ability to obtain capital at competitive rates and ability to exist as a going concern. It is possible that stranded cost exposure before mitigation could exceed the Company's current total common stock equity. Inflation - The annual rate of inflation, as measured by the Consumer Price Index, was 2.2% for 1999, 1.6% for 1998 and 1.7% for 1997. The Company's revenues, however, are based on rate regulation that generally recognizes only historical costs. Although the rate of inflation has eased, it continues to have an impact on most aspects of the business. Recent Accounting Pronouncements - In June 1997, the Financial Accounting Standards Board ("FASB") issued SFAS No. 130, Reporting Comprehensive Income, effective for fiscal years beginning after December 15, 1997. SFAS No. 130 established standards for reporting and display of comprehensive income and its components in a full set of general-purpose financial statements. It requires that an enterprise classify items of other comprehensive income by their nature in a financial statement and display the accumulated balance of other comprehensive income separately in the equity section of a statement of financial position. In 1999 and 1998 the Company recognized a pre-tax minimum pension liability adjustment of $0.4 million and $0.6 million, respectively, or $0.1 million and $0.4 million net of tax, respectively. In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. In June 1999, the FASB issued Statement No. 137, Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of SFAS No. 133. This Statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. This Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133, as amended, is effective for fiscal years beginning after June 15, 2000. A company may also implement this Statement as of the beginning of any fiscal quarter after issuance (that is, fiscal quarters beginning June 16, 1998 and thereafter). SFAS No. 133 cannot be applied retroactively. SFAS No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts. With respect to hybrid instruments, a company may elect to apply SFAS 133, as amended, to (1) all hybrid contracts, (2) only those hybrid instruments that were issued, acquired, or substantively modified after December 31, 1997, or (3) only those hybrid instruments that were issued, acquired, or substantively modified after December 31, 1998. The Company has not yet quantified the impacts of adopting SFAS No. 133 on the financial statements and has not determined the timing or method of the adoption of SFAS No. 133. Effective January 1, 1999, the Company adopted EITF No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. EITF Issue 98-10 requires energy trading contracts to be recorded at fair value on the balance sheet, with the changes in fair value included in earnings. In 1999, the Company recognized a net gain of $.2 million in the accompanying Consolidated Statement of Income for its open electricity purchase and sale commitments. As discussed in Note 1, the Company decided to terminate its trading alliance with Virginia Power during the third quarter of 1999 and the Company does not intend to continue its trading operations following the maturity of its remaining open contracts in 2000. Forward Looking Statements - This document contains statements that are forward looking. These statements are based on current expectations that are subject to risks and uncertainties. Actual results will depend, among other things, upon general economic and business conditions, weather, the actions of regulators, including the outcome of the litigation involving Connecticut Valley before the FERC and the Court and the Company's pending rate case before the PSB and associated appeal to the Vermont Supreme Court, as well as other factors which are described in further detail in the Company's filings with the Securities and Exchange Commission. The Company cannot predict the outcome of any of these proceedings or other factors. Item 8. Financial Statements and Supplementary Data. Index to Financial Statements and Supplementary Data Page No. Report of Independent Public Accountants. . . . . . . . . . . 57 Financial Statements: Consolidated Statement of Income for each of the three years ended December 31, 1999 . . . . . . . . . . . 58 Consolidated Statement of Cash Flows for each of the three years ended December 31, 1999 . . . . . . . . . 59 Consolidated Balance Sheet at December 31, 1999 and 1998 . . . . . . . . . . . . . . . . . . . . . . . . . 60 Consolidated Statement of Capitalization at December 31, 1999 and 1998 . . . . . . . . . . . . . . . . 61 Consolidated Statement of Changes in Common Stock Equity for each of the three years ended December 31, 1999 . . . . . . . . . . . . . . . . . . . . 62 Notes to Consolidated Financial Statements . . . . . . . . 63 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 (the Company) as of December 31, 1999 and 1998, 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, 1999. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Central Vermont Public Service Corporation and its wholly owned subsidiaries as of December 31, 1999 and 1998 and the results of their operations and cash flows for each of the three years in the period ended December 31, 1999 in conformity with generally accepted accounting principles. As discussed in Note 13, the Company has filed with the Federal Energy Regulatory Commission a request for an exit fee mechanism to cover the stranded costs resulting from the anticipated cancellation of the power contract between the Company and its wholly owned subsidiary Connecticut Valley. If the Company is unable to obtain an order authorizing the recovery of a significant portion of the exit fee, or other appropriate stranded cost mechanism, the Company would be required to recognize a loss under this contract of a material amount. The Company is also involved in related litigation in the federal courts. Additionally, on October 27, 1998, the Company reached a settlement agreement on rates with the Vermont Public Service Board (PSB). The agreement incorporates a disallowance of a portion of the Company's purchased power cost under its Hydro-Quebec contracts while the Vermont Supreme Court is reviewing the Company's claim that the PSB is precluded from again trying the Company on certain Hydro-Quebec contract issues. If the ultimate resolution of these proceedings, including any proceedings by the PSB subsequent to a Vermont Supreme Court decision, is unfavorable to the Company, the result would have a significant adverse impact on the Company and could impact the Company's financial viability. ARTHUR ANDERSEN LLP Boston, Massachusetts February 7, 2000 (except with respect to the matter discussed in Note 13 as to which the date is March 6, 2000).
CONSOLIDATED STATEMENT OF INCOME (Dollars in thousands, except per share amounts) Year Ended December 31 1999 1998 1997 Operating Revenues $419,815 $303,835 $304,732 -------- -------- -------- Operating Expenses Operation Purchased power 269,386 184,887 171,443 Production and transmission 22,575 23,383 22,417 Other operation 46,967 44,110 40,909 Maintenance 17,613 15,613 15,333 Depreciation 16,955 16,708 16,931 Other taxes, principally property taxes 11,308 11,426 11,490 Taxes on income 10,360 (283) 7,573 -------- -------- -------- Total operating expenses 395,164 295,844 286,096 -------- -------- -------- Operating Income 24,651 7,991 18,636 Other Income and Deductions -------- -------- -------- Equity in earnings of affiliates 2,844 3,191 3,214 Allowance for equity funds during construction - 61 75 Other income, net 1,282 3,826 6,522 Provision for income taxes (35) (426) (1,590) -------- -------- -------- Total other income and deductions, net 4,091 6,652 8,221 -------- -------- -------- Total Operating and Other Income 28,742 14,643 26,857 Interest Expense -------- -------- -------- Interest on long-term debt 10,651 9,868 9,337 Other interest 1,548 831 400 Allowance for borrowed funds during construction (41) (39) (31) -------- -------- -------- Total interest expense, net 12,158 10,660 9,706 -------- -------- -------- Net Income Before Extraordinary Charge 16,584 3,983 17,151 Extraordinary Charge Net of Taxes - - 811 -------- -------- -------- Net Income 16,584 3,983 16,340 Preferred Stock Dividends Requirements 1,862 1,945 2,028 -------- -------- -------- Earnings Available For Common Stock $ 14,722 $ 2,038 $ 14,312 ======== ======== ======== Average Shares of Common Stock Outstanding 11,463,197 11,439,688 11,458,735 Basic and Diluted Share of Common Stock: Earnings before extraordinary charge $1.28 $ .18 $1.32 Extraordinary charge - - .07 Earnings Per Basic and Diluted Share of Common Stock $1.28 $ .18 $1.25 Dividends Paid Per Share of Common Stock $ .88 $ .88 $ .88 The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS (Dollars in thousands) Year Ended December 31 1999 1998 1997 Cash Flows Provided (Used)By: Operating Activities Net income $16,584 $ 3,983 $16,340 Adjustments to reconcile net income to net cash provided by operating activities Equity in earnings of affiliates (2,844) (3,191) (3,214) Dividends received from affiliates 2,739 3,267 3,216 Equity in earnings from non-utility investments 795 (6,740) (5,378) Distribution of earnings from non-utility investments 4,390 4,744 4,403 Depreciation 16,955 16,708 16,931 Amortization of capital leases 1,093 1,082 1,081 Deferred income taxes and investment tax credits 1,971 (5,989) (6,529) Extraordinary charge - - 1,198 Allowance for equity funds during construction - (61) (75) Net deferral and amortization of nuclear replacement energy and maintenance costs (4,914) (1,657) 4,913 Amortization of conservation & load management costs 6,613 5,202 7,018 Net deferral and amortization of restructuring costs - (1,075) - Gain on sale of assets - - (4,986) (Increase) decrease in accounts receivable and unbilled revenues (11,138) (5,465) 855 Increase in accounts payable 3,315 6,543 668 Increase (decrease) in accrued income taxes (2,300) (3,656) 4,168 Change in other working capital items 588 (4,094) 3,532 Change in environmental reserve 68 6,848 591 Other, net (2,683) 5,294 (2,758) ------- ------- ------- Net cash provided by operating activities 31,232 21,743 41,974 ------- ------- ------- Investing Activities Construction and plant expenditures (13,231) (16,046) (13,841) Conservation and load management expenditures (2,440) (2,208) (1,837) Return of capital 186 233 233 Proceeds from sale of assets 88 - 6,374 Special deposit - 2,946 2,283 Non-utility investments (14,338) (3,046) (1,197) Other investments, net (198) (251) 54 ------- ------- ------- Net cash used for investing activities (29,933) (18,372) (7,931) ------- ------- ------- Financing Activities Sale (repurchase) of common stock 75 494 (1,072) Short-term debt, net (40,585) 24,350 (5,100) Long-term debt, net 78,674 (20,520) (3,019) Retirement of preferred stock (1,000) (1,000) (1,000) Common and preferred dividends paid (11,950) (12,006) (12,630) Reduction in capital lease obligations (1,092) (1,082) (1,081) Other (11) (62) - ------- ------- ------- Net cash provided (used) for financing activities 24,111 (9,826) (23,902) ------- ------- ------- Net Increase (Decrease) In Cash and Cash Equivalents 25,410 (6,455) 10,141 Cash and Cash Equivalents at Beginning of Year 10,051 16,506 6,365 ------- ------- ------- Cash and Cash Equivalents at End of Year $35,461 $10,051 $16,506 ======= ======= ======= Supplemental Cash Flow Information Cash paid during the year for: Interest (net of amounts capitalized) $ 9,207 $10,267 $ 9,476 Income taxes (net of refunds) $10,935 $ 9,556 $10,654 Non-cash Operating, Investing and Financing Activities Receivables purchase agreement (Note 10) Regulatory assets (Notes 1,2 and 12) Long-term lease arrangements (Note 14) The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED BALANCE SHEET (Dollars in thousands) December 31 Assets 1999 1998 Utility Plant, at original cost $475,845 $469,204 Less accumulated depreciation 173,605 160,666 -------- -------- 302,240 308,538 Construction work in progress 11,315 10,461 Nuclear fuel, net 1,177 948 -------- -------- Net utility plant 314,732 319,947 -------- -------- Investments and Other Assets Investments in affiliates, at equity 25,501 26,142 Non-utility investments 45,269 35,896 Non-utility property, less accumulated depreciation 2,513 2,920 -------- -------- Total investments and other assets 73,283 64,958 -------- -------- Current Assets Cash and cash equivalents 35,461 10,051 Special deposits 113 424 Accounts receivable, less allowance for uncollectible accounts ($1,595 in 1999 and $2,242 in 1998) 38,381 29,224 Unbilled revenues 20,605 18,677 Materials and supplies, at average cost 3,126 3,746 Prepayments 1,964 1,881 Other current assets 6,510 9,768 -------- -------- Total current assets 106,160 73,771 -------- -------- Regulatory Assets 62,808 66,208 -------- -------- Other Deferred Charges 6,976 5,398 -------- -------- Total Assets $563,959 $530,282 ======== ======== Capitalization And Liabilities Capitalization Common stock equity $184,021 $179,182 Preferred and preference stock 8,054 8,054 Preferred stock with sinking fund requirements 17,000 18,000 Long-term debt 155,251 90,077 Capital lease obligations 15,060 16,141 -------- -------- Total capitalization 379,386 311,454 -------- -------- Current Liabilities Short-term debt - 37,000 Current portion of long-term debt 16,688 6,773 Accounts payable 14,843 11,589 Accounts payable - affiliates 12,311 11,784 Accrued income taxes 675 2,975 Dividends declared 2,523 2,521 Nuclear decommissioning costs 3,457 4,820 Disallowed purchased power costs 2,859 7,361 Other current liabilities 18,823 17,403 -------- -------- Total current liabilities 72,179 102,226 -------- -------- Deferred Credits Deferred income taxes 48,631 47,581 Deferred investment tax credits 6,440 6,831 Nuclear decommissioning costs 18,548 23,239 Other deferred credits 38,775 38,951 -------- -------- Total deferred credits 112,394 116,602 -------- -------- Commitments and Contingencies Total Capitalization and Liabilities $563,959 $530,282 ======== ======== The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CAPITALIZATION (Dollars in thousands) December 31 1999 1998 Common Stock Equity Common stock, $6 par value, authorized 19,000,000 shares; issued 11,785,848 shares $ 70,715 $ 70,715 Other paid-in capital 45,340 45,318 Accumulated other comprehensive income (246) (365) Treasury stock (319,043 shares and 324,717 shares, respectively, at cost) (4,159) (4,234) Retained earnings 72,371 67,748 -------- -------- Total common stock equity 184,021 179,182 -------- -------- 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; 170,000 shares 17,000 18,000 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 25,054 26,054 -------- -------- Long-Term Debt First Mortgage Bonds 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 15,000 18,000 8.91 % Series JJ, due 2031 15,000 15,000 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 Second Mortgage Bonds 8.125%, due 2004 75,000 - Vermont Industrial Development Authority Bonds Variable, due 2013 (3.90% at December 31, 1999) 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 (3.35% at December 31, 1999) 5,000 5,000 Other, various 7,139 4,050 -------- -------- 171,939 96,850 Less current portion 16,688 6,773 -------- -------- Total long-term debt 155,251 90,077 -------- -------- Capital Lease Obligations 15,060 16,141 -------- -------- Total Capitalization $379,386 $311,454 ======== ======== The accompanying notes are an integral part of these consolidated financial statements.
CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCK EQUITY (Dollars in thousands) Accumulated Other Other Common Stock Paid-in Comprehensive Treasury Retained Shares Amount Capital Income Stock Earnings Total ------ ------ ------- ------------ -------- -------- -------- Balance, December 31, 1996 11,519,748 $70,715 $45,273 - $(3,656) $74,137 $186,469 Treasury stock at cost (96,347) (1,072) (1,072) Net income 16,340 16,340 Cash dividends on capital stock: Common stock - $.88 per share (12,608) (12,608) Cumulative preferred stock: Non-redeemable (368) (368) Redeemable (1,660) (1,660) Amortization of preferred stock issuance expenses 22 22 ------- ----- ----- ----- ------ ------- ------- Balance, December 31, 1997 11,423,401 70,715 45,295 - (4,728) 75,841 187,123 Treasury stock at cost 37,730 494 494 Net income 3,983 3,983 Other comprehensive income net of taxes (365) (365) Cash dividends on capital stock: Common stock - $.88 per share (10,131) (10,131) Cumulative preferred stock: Non-redeemable (368) (368) Redeemable (1,577) (1,577) Amortization of preferred stock issuance expenses 23 23 ---------- ------- ------- ------- ------- -------- -------- Balance, December 31, 1998 11,461,131 70,715 45,318 (365) (4,234) 67,748 179,182 Treasury stock at cost 5,674 75 75 Net income 16,584 16,584 Other comprehensive income net of taxes 119 119 Cash dividends on capital stock Common stock - $.88 per share (10,099) (10,099) Cumulative preferred stock: Non-redeemable (368) (368) Redeemable (1,494) (1,494) Amortization of preferred stock issuance expenses 22 22 ---------- ------- ------- ------- ------- ------- -------- Balance, December 31, 1999 11,466,805 $70,715 $45,340 (246) $(4,159) $72,371 $184,021 ========== ======= ======= ======= ======= ======= ======== 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 PSB, the NHPUC and the FERC, 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 SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," for both the Company's regulated Vermont service territory and FERC regulated wholesale business. 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 would no longer apply to the Company's regulated operations. 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. 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. Management periodically reviews these criteria to ensure the continuing application of SFAS No. 71 is appropriate. Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, management believes that its regulatory assets are probable of future recovery in the state of Vermont for the Company's retail business. However, such recovery of regulatory assets is not probable in the state of Hew Hampshire for Connecticut Valley. As a result of legal and regulatory actions described in Note 13 below, in 1998, management determined to discontinue the application of regulatory accounting principles applied to Connecticut Valley. As such, Connecticut Valley wrote off in 1998 regulatory assets of approximately $1.3 million on a pre-tax basis. For additional information see Note 13 below. Unregulated Business - The Company's two wholly owned non-regulated subsidiaries, Catamount and SmartEnergy, results of operations are included in Other income, 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. Catamount's costs incurred subsequent to obtaining financial viability are recognized as assets subject to depreciation or amortization in accordance with industry practice. Project viability is obtained when it becomes probable that costs incurred will generate future economic benefits sufficient to recover these costs. Revenues - Estimated unbilled revenues are recorded at the end of accounting periods. For 1999 and 1998, operating revenues include $100.1 million and $11.3 million related to the Virginia Power alliance which was effectively terminated by the Company during the third quarter of 1999. 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 3.54% of the cost of depreciable utility plant for each of the years 1997 through 1999. Income Taxes - In accordance with SFAS No. 109, "Accounting for Income Taxes", the Company 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. 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 or 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 9.38%, 8.62% and 5.52% for the years 1997 through 1999, respectively. Regulatory Assets - Certain costs are deferred and amortized in accordance with authorized or expected rate-making treatment. The major components of regulatory assets reflected in the Consolidated Balance Sheet as of December 31, are as follows (dollars in thousands):
1999 1998 ---- ---- Conservation and load management $13,173 $15,611 Restructuring costs 3,757 5,087 Nuclear refueling outage costs 8,149 2,948 Income taxes 8,429 9,613 Year 2000 costs and technologies initiatives 2,766 2,204 Dismantling costs: Maine Yankee nuclear power plant 12,785 15,228 Connecticut Yankee nuclear power plant 8,351 9,971 Yankee Atomic nuclear power plant 870 2,860 Hydro-Quebec arbitration costs 1,970 - Unrecovered plant and regulatory study costs 1,700 1,875 Other regulatory assets 858 811 ------- ------- $62,808 $66,208 ======= =======
The Company earns a return on the unamortized C&LM and replacement energy and maintenance costs. During regular nuclear refueling outages, the incremental 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 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, Connecticut Yankee and Maine Yankee is provided without a return on investment through mid-2000, 2007 and 2008, respectively. See Note 2 below for discussion of the costs associated with the discontinued operations of the Yankee Atomic, Connecticut Yankee and Maine Yankee nuclear power plants. In addition, the Company is not earning a return on approximately $7.4 million of restructuring, Year 2000 and other unamortized regulatory assets which are being recovered over periods ranging from two to 33 years. Recovery of $2.0 million of Hydro-Quebec arbitration costs will be determined in the next rate proceeding. 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 14, 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. For 1999 and 1998 purchased power includes $100.6 million and $10.2 million related to the Virginia Power alliance which was effectively terminated by the Company during the third quarter of 1999. Valuation of Long-Lived Assets - The Company periodically evaluates the carrying value of long-lived assets and long-lived assets to be disposed of, including its investments in nuclear generating companies and its interests in jointly owned generating facilities, when events and circumstances warrant such a review. The carrying value of such assets is considered impaired when the anticipated undiscounted cash flow from such an asset is separately identifiable and is less than its carrying value. In that event, a loss is recognized based on the amount by which the carrying value exceeds the fair market value of the long-lived asset. Based on management's estimates, no impairment of long-lived assets exists as of December 31, 1999. 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. 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 1999 1998 Nuclear generating companies: Vermont Yankee Nuclear Power Corporation 31.3% $16,745 $16,969 Connecticut Yankee Atomic Power Company 2.0% 2,097 2,094 Maine Yankee Atomic Power Company 2.0% 1,488 1,578 Yankee Atomic Electric Company 3.5% 549 690 ------- ------- 20,879 21,331 Vermont Electric Power Company, Inc.: Common stock 56.8% 3,513 3,513 Preferred stock 1,109 1,298 ------- ------- $25,501 $26,142 ======= =======
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 Total Share of Date of Estimated CVPS Funded Study Obligation Obligation Obligation Nuclear generating companies: Vermont Yankee 1993 $312.7 $109.4 $73.4 Maine Yankee 1998 $343.9 $6.9 $ 3.6 Connecticut Yankee 1996 $426.7 $8.5 $ 3.6 Yankee Atomic 1994 $370.0 $13.0 $ 5.4
Vermont Yankee Vermont Yankee's current decommissioning cost study is based on a 1994 site study. The FERC approved settlement agreement allowed $312.7 million, in 1993 dollars, as the estimated decommissioning cost. Based on the study's assumed cost escalation rate of 5.4% per annum and an expiration of the Plant's operating license in the year 2012, the estimated current cost of decommissioning is $428.7 million and, at the end of 2012, is approximately $816.6 million. The present value of the pro rata portion of decommissioning costs recorded to date is $290.0 million of which the Company's share is $101.5 million. Under the FERC approved settlement agreement, Vermont Yankee was required to file with FERC an updated decommissioning cost study by April 1, 1999. On May 13, 1999, in light of the ongoing discussions involving the possible sale of the Vermont Yankee Nuclear Power plant, the FERC approved a settlement agreement extending the required filing date to April 1, 2000. On November 17, 1999, Vermont Yankee executed an Asset Purchase Agreement with AmerGen Energy Co. The sale of the nuclear generating plant would transfer responsibility for decommissioning the plant to the new owner. Additionally, Vermont Yankee's current owners will make a one-time payment currently estimated at $54.3 million to pre-pay the plant's decommissioning fund at $312.7 million. In return, AmerGen will assume full responsibility for all future operating costs and the estimated $816.6 million price tag for decommissioning the plant at the end of its operating license in 2012. The agreement is subject to several conditions, including approvals or specific rulings by various regulatory authorities. As such, execution of the agreement does not provide assurance that the sale will occur. This agreement also involves the Company entering into a contract to purchase a portion of the power produced by this plant. Maine Yankee In 1997 the Maine Yankee's nuclear power plant was prematurely retired from commercial operation. The Company relied on Maine Yankee for less than 5% of its required system capacity. Future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee are estimated to be approximately $715.0 million in 1998 dollars including a decommissioning obligation of $344.0 million. On January 19, 1999, Maine Yankee and the active intervenors filed an Offer of Settlement with the FERC which the FERC approved. As a result, all issues raised in the FERC proceeding, including recovery of anticipated future payments for closing, decommissioning and recovery of the remaining investment in Maine Yankee are resolved. Also resolved are the issues raised by the secondary purchasers, who purchased Maine Yankee power through agreements with the original owners, by limiting the amounts they will pay for decommissioning the Maine Yankee plant and by settling other points of contention affecting individual secondary purchasers. As a result, it is possible that the Company will not be able to recover approximately $.5 million of these costs. Connecticut Yankee In 1996 the Connecticut Yankee Nuclear power plant was prematurely retired from commercial operation. The Company relied on Connecticut Yankee for less than 3.0% of its required system capacity. On August 31, 1998, a FERC Administrative Law Judge recommended that the owners of Connecticut Yankee, including the Company, may collect from customers $350.0 million for decommissioning the Connecticut Yankee Nuclear Power Plant rather than the $426.7 million requested. The Administrative Law Judge ruling is subject to approval by the FERC Commissioners. If approved, it is possible that the Company would not be able to recover approximately $1.5 million of decommissioning costs through the regulatory process. Yankee Atomic In 1992, the Yankee Atomic nuclear power plant was retired from commercial operation. The Company relied on Yankee Atomic for less than 1.5% of its system capacity. Maine Yankee, Connecticut Yankee and Yankee Atomic Decommissioning Costs Presently, costs billed to the Company by Maine Yankee, Connecticut Yankee and Yankee Atomic, including a provision for ultimate decommissioning of the units, are being collected from the Company's customers through existing retail and wholesale rate tariffs. The Company's share of remaining costs with respect to Maine Yankee, Connecticut Yankee and Yankee Atomic's decisions to discontinue operation, including the costs in the table above, is estimated to be $12.8 million, $8.4 million and $.9 million, respectively, at December 31, 1999. These amounts are subject to ongoing review and revisions and are reflected in the accompanying balance sheet both as regulatory assets and nuclear dismantling liabilities (current and non-current). The decision to prematurely retire these nuclear power plants was based on economic analyses of the costs of operating them compared to the costs of closing them and incurring replacement power costs over the remaining period of the plants' operating licenses. The Company believes that based on the current regulatory process, its proportionate share of Maine Yankee, 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 three plants has not and will not have a material adverse effect on the Company's earnings or financial condition. Nuclear Insurance The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $9.7 billion. Beyond that a licensee is indemnified under the Price-Anderson Act, 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 $9.5 billion per incident by assessing $88.1 million against each of the 108 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 adjusted at least every five years to reflect inflationary changes. Currently the Company's interests in the nuclear power units are such that it could become liable for an aggregate of approximately $3.7 million of such maximum assessment per incident per year. Vermont Yankee Summarized financial information for Vermont Yankee Nuclear Power Corporation is as follows (dollars in thousands):
Earnings 1999 1998 1997 Operating revenues $208,812 $195,249 $173,106 Operating income $14,932 $15,282 $13,961 Net income $6,471 $7,125 $6,834 Company's equity in net income $2,022 $2,218 $2,144
December 31 Investment 1999 1998 Current assets $ 45,824 $ 36,947 Non-current assets 639,718 598,927 -------- -------- Total assets 685,542 635,874 Less: Current liabilities 46,886 32,250 Non-current liabilities 584,728 548,981 -------- -------- Net assets $ 53,928 $ 54,643 ======== ======== Company's equity in net assets $ 16,745 $ 16,969
Included in Vermont Yankee's revenues shown above are sales to the Company of $58.6 million,$59.1 and $65.0 million for 1997 through 1999, respectively. These amounts are reflected as purchased power, net of deferrals and amortization, in the accompanying Consolidated Statement of Income. VELCO 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 expenses in the accompanying Consolidated Statement of Income) amounting to $8.7 million, $8.8 million and $8.6 million for 1997 through 1999, 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 continued in full force and effect until May 1995 and was extended for an additional two-year term in May 1995, 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 1999 1998 1997 Transmission revenues $16,935 $17,268 $18,481 Operating income $ 2,633 $ 2,691 $ 2,773 Net income $ 1,221 $ 1,153 $ 1,213 Company's equity in net income $638 $581 $618
December 31 Investment 1999 1998 Current assets $19,289 $20,430 Non-current assets 48,005 47,228 ------- ------- Total assets 67,294 67,658 Less: Current liabilities 26,434 22,093 Non-current liabilities 32,297 36,597 ------- ------- Net assets $ 8,563 $ 8,968 ======= ======= Company's equity in net assets $ 4,622 $ 4,811
Note 3 Non-utility investments Catamount The Company's wholly owned subsidiary, Catamount, invests through its wholly owned subsidiaries, in non-regulated, energy-related projects in Western Europe and North America. Catamount's earnings were $2.1 million, $3.3 million and $4.1 million for 1999, 1998 and 1997, respectively. Earnings for 1997 reflect a net of tax gain of approximately $1.8 million from the sale of NW Energy Williams Lake L.P. 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 1999 1998 Rumford Cogeneration Co. L.P. Maine 85MW Coal/Wood 1990 15.1% $14,358 $13,273 Ryegate Associates Vermont 20MW Wood 1992 33.1% 6,391 6,305 Appomattox Cogeneration L.P. Virginia 41MW Coal/Biomass 1982 25.3% 4,244 4,079 Black liquor Rupert Cogeneration Partners, Ltd. Idaho 10MW Gas 1996 50.0% 1,826 1,775 Glenns Ferry Cogeneration Partners, Ltd. Idaho 10MW Gas 1996 50.0% 1,529 1,387 Fibrothetford Limited Thetford, England 38.5MW Biomass 1998 44.0% 7,757 8,556 Heartlands Power Limited Fort Dunlop, England 98MW Gas 1999 50.0% 7,030 421 ------- ------- $43,135 $35,796 ===== =====
On December 21,1999 Catamount invested $.4 million to purchase a 50% interest in Heartlands Power Limited ("Heartlands"). Heartlands was formed by Rolls-Royce Power Ventures to develop, construct and own a 98MW natural gas-fired power station in Fort Dunlop, England. Catamount also loaned the project $6.6 million. Catamount currently has a $1.2 million letter of credit outstanding to support certain of its obligations in connection with a debt service requirement in the Appomattox Cogeneration project and aggregated letters of credit of $11.0 million in support of construction and equity commitments for its Gauley River Power project. The Company currently owns 100% of the Gauley River Power project, however, as a result of regulatory requirements to reduce its ownership to a non-controlling level in order to meet Qualifying Facility status following completion of the project, this investment has not been consolidated in the accompanying financial statements as the Company's control is considered temporary. SmartEnergy Another wholly owned subsidiary of the Company, SmartEnergy, invests in unregulated energy and service related businesses, including its 70% ownership interest in HSS. Overall, SmartEnergy incurred net losses of $2.9 million, $1.5 million and $.7 million for 1999, 1998 and 1997, respectively. HSS establishes a network of affiliate contractors who perform home maintenance, repair and improvement needs via membership. Although SmartEnergy owns a 70% interest in HSS, this investment is accounted for using the equity method on the basis that financing plans will be completed in early 2000 which will have the effect of diluting SmartEnergy's ownership to a less than 50% level. HSS is seeking equity investors to finance the national rollout of this business. HSS began operations in 1999 and is subject to risks and challenges similar to a company in the early stage of development. HSS' pre-tax loss for 1999 was $7.1 million, of which SmartEnergy's share is $5.3 million. As of December 31, 1999, SmartEnergy has a net investment of $2.1 million. Note 4 Common Stock Through a common stock repurchase program which was suspended in 1997, the Company purchased from time to time 362,447 shares of its common stock in open market transactions at an average price of $13.04 per share. These transactions, net of 43,404 shares sold in connection with the Company's stock option plans, are recorded as treasury stock, at cost, in the Company's Consolidated Balance Sheet. Note 5 Redeemable preferred stock 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. Since the Company's redeemable preferred stock was issued in a private placement, it is not practicable to estimate the fair value. Note 6 Stock Option Plans The Company has issued stock to key employees and non-employee directors under various option plans approved in 1988, 1993, 1997 and 1998 which authorize the granting of options with respect to 1,025,875 shares of the Company's common stock. Options are granted at prices not less than 100% of the fair market value at the date of the option grant. Shares available for future grants under the 1997 and 1998 stock option plans were 107,890 at December 31, 1999. No additional grants may be given under the 1988 and 1993 plans. Option activity during the past three years was as follows:
Average Option Stock Price Options Options outstanding at December 31, 1996 $18.1271 299,975 Options exercised - - Options granted 10.9900 126,750 Options expired 20.5416 (10,500) -------- ------- Options outstanding at December 31, 1997 15.8928 416,225 Options exercised 11.6505 (34,475) Options granted 14.6286 154,500 Options expired 24.3750 (20,250) -------- ------- Options outstanding at December 31, 1998 15.4649 516,000 Options exercised 10.9375 (2,250) Options granted 10.5742 95,860 Options expired 18.0476 (24,750) -------- ------- Options outstanding at December 31, 1999 $14.5714 584,860 ======== =======
The price range of options outstanding at December 31, 1999 is $10.5625 to $24.3125. The weighted average remaining contractual life at December 31, 1999 is 6.69 years and the weighted average exercise price is $14.5513. Exercisable options at December 31,1999 total 474,610 and the weighted average exercise price is $13.5854. The Company accounts for these plans under Accounting Principles Board Opinion No. 25, under which no compensation cost has been recognized. Under SFAS No. 123, "Accounting for Stock-Based Compensation," all awards granted must be recognized in compensation cost. Had compensation cost for these plans been determined consistent with SFAS No. 123, the Company's net income and earnings per share of common stock would have been reduced to the following pro forma amounts as follows(dollars in thousands, except per share amounts):
1999 1998 1997 ---- ---- ---- Net Income As reported $16,584 $3,983 $16,340 Pro forma 16,518 $3,930 $16,309 Earnings per share of common stock As reported $1.28 $.18 $1.25 Pro forma $1.27 $.17 $1.25
The Company chose the Binomial model to project an estimate of appreciation of the underlying shares of the stock during the respective option term. The average assumptions used were as follows:
1999 1998 1997 ---- ---- ---- Volatility .2982 .1861 .1808 Risk free rate of return 5.50% 6.25% 6.50% Dividend yield 7.26% 6.57% 7.13% Expected life in years 5-10 5-10 5-10
Note 7 Long-term debt and sinking fund requirements Utility On July 30, 1999 the Company sold $75.0 million aggregate principal amount of 8 1/8% Second Mortgage Bonds due 2004 at a price of 99.915%. The Company and its subsidiaries' long-term debt contains financial and non-financial covenants. At December 31, 1999 the Company and its subsidiaries were in compliance with all debt covenants related to its various debt agreements. Based on outstanding debt at December 31, 1999, the aggregate amount of long-term debt maturities and sinking fund requirements are $16.7 million, $4.2 million, $7.2 million, $16.1 million and $75.2 million for the years 2000 through 2004, respectively. Substantially all utility property and plant is subject to liens under the First and Second Mortgage Bonds. Non-Utility On November 12, 1998, Catamount replaced its $8.0 million credit facility with a $25.0 million revolving credit/term loan facility maturing November 2006 which provides for up to $25.0 million in revolving credit loans and letters of credit. This facility has a security interest in Catamount's assets. 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 aggregated letters of credit of $11.0 million in support of construction and equity commitments for its Gauley River Power project. SmartEnergy Water Heating Services, Inc., a wholly owned subsidiary of SmartEnergy, has a secured seven-year term loan with Bank of New Hampshire with an outstanding balance of $1.3 million at December 31, 1999. The interest rate is fixed at 9.25% per annum. Financial obligations of the Company's subsidiaries are non-recourse to the Company. Note 8 Short-term debt Utility The Company had no short-term debt outstanding at December 31, 1999 and had $37.0 million at December 31, 1998 at average interest rate of 5.94%. The Company had a $50.0 million revolving credit facility with a group of banks which matured and was repaid in 1999. $25.0 million of this facility was outstanding at December 31, 1998. The Company has an aggregate of $16.9 million of letters of credit with termination dates that have been extended to May 31, 2000. These letters of credit are subject to a first mortgage interest in the same collateral supporting the Company's first mortgage bonds. In addition, the Company had a $12.0 million accounts receivable facility which was repaid by the Company in November 1999. Note 9 Financial instruments The estimated fair values of the Company's financial instruments at December 31, 1999 and 1998 are as follows (dollars in thousands): 1999 1998 ------------------- ------------------ Carrying Fair Carrying Fair Amount Value Amount Value --------- -------- -------- --------- Long-term debt $171,939 $160,419 $96,850 $101,776 The carrying amount for cash and cash equivalents and short-term debt approximates fair value because of the short maturity of those instruments. The fair value of the Company's 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. The Company believes that any excess or shortfall 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 not result in a material impact on the Company's financial position or results of operations. Note 10 Receivables purchase agreement Pursuant to SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," the Company classified amounts transferred under its receivable purchase agreement as secured borrowings. The facility matured and was repaid on November 29, 1999. Those amounts related to the accounts receivable facility are shown at December 31, 1998 as short-term debt. Note 11 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 following table sets forth the funded status of the pension plan and amounts recognized in the Company's Consolidated Balance Sheet and Statement of Income (dollars in thousands):
December 31 1999 1998 Projected benefit obligation $54,172 $63,095 Fair value of plan assets (primarily equity and fixed income securities) 79,834 65,602 Projected benefit obligation less ------- ------- than fair value of plan assets (25,662) (2,507) Unrecognized net transition obligation 728 647 Unrecognized prior service costs (2,084) (2,681) Unrecognized net gain 35,961 15,561 ------- ------- Accrued pension liability $ 8,943 $11,020 ======= =======
1999 1998 1997 Net pension costs include the following components Service cost $ 1,854 $ 1,802 $ 1,802 Interest cost 4,035 4,459 4,307 Expected return on plan assets (5,081) (4,720) (4,756) Net amortization and deferral 45 778 140 -------- ------- ------- Pension costs 853 2,319 1,493 Less amount allocated to other accounts 107 228 249 ------- ------- ------- Net pension costs expensed $ 746 $ 2,091 $ 1,244 ======= ======= =======
Assumptions used in calculating pension cost were as follows:
December 31 1999 1998 Weighted average discount rates 7.75% 6.75% Expected long-term return on assets 9.25% 9.50% Rate of increase in future compensation levels 4.50% 4.00%
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 funds this 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 Consolidated Balance Sheet and Statement of Income in accordance with SFAS No. 106 (dollars in thousands):
December 31 1999 1998 Accumulated postretirement benefit obligation $11,545 $10,757 Unrecognized transition obligation (3,326) (3,582) Unrecognized net loss (2,112) (1,329) ------ ------- Accrued postretirement benefit cost 6,107 5,846 Less regulatory asset for restructuring costs 1,370 1,954 Effective accrued postretirement benefit ------ ------- costs $ 4,737 $ 3,892 ======= =======
1999 1998 1997 Net postretirement benefit cost includes the following components Service cost $ 214 $ 194 $ 197 Interest cost 892 815 716 Expected return on plan assets (87) (160) (145) Amortization of transition obligation over a twenty-year period, of regulatory asset and of net actuarial loss 843 837 408 ------ ------ ------ Effective postretirement benefit cost 1,862 1,686 1,176 Less amount allocated to other accounts 171 209 192 ------ ------ ------ Net postretirement benefit cost expensed $1,691 $1,477 $ 984 ====== ====== ======
Assumptions used in the per capita costs of the accumulated postretirement benefit obligation were as follows:
December 31 1999 1998 Per capita percent increase in health care costs: Pre-65 6.50% 6.50% Post-65 5.50% 5.50% Weighted average discount rates 7.75% 6.75% Rate of increase in future compensation levels 4.50% 4.00% Long-term return on assets 8.50% 8.50%
Health care costs are assumed to decrease to 6.0% for people under 65 years of age for the year 2001 and thereafter and remain at 5.5% for people over 65 years of age for the year 2000 and thereafter. Increasing (decreasing) the assumed health care cost trend rates by one percentage point in each year would have resulted in an increase (decrease) of $657,000 and $(563,000), respectively, in the accumulated postretirement benefit obligation as of December 31, 1999, and an increase (decrease) of about $45,000 and $(39,000), respectively, in the aggregate of the service cost and interest cost components of net periodic postretirement benefit cost for 1999. The Company provides postemployment benefits consisting of long-term disability benefits. The accumulated postemployment benefit obligation at December 31, 1999 and 1998 of $.8 million and $.7 million, respectively, is reflected in the accompanying Consolidated Balance Sheet as a liability and is offset by a corresponding regulatory asset of $.3 million for 1999 and $.5 million for 1998. 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 post-employment benefit costs charged to expense in 1999, 1998 and 1997, including insurance premiums, were $281,000, $118,000 and $247,000, respectively (pre-tax). In the third quarter of 1997, the Company offered and recorded obligations related to a voluntary retirement and severance programs to employees. The estimated benefit obligation for the retirement program as of December 31, 1999 is approximately $2.8 million. This amount consists of pension benefits and post-retirement medical benefits of $1.4 million and $1.4 million, respectively. The estimated benefit obligation for the severance program which included termination pay as well as other costs, is about $1.0 million as of December 31, 1999. These obligations, deferred pursuant to a PSB Accounting Order dated September 30, 1997, are reflected in the accompanying Consolidated Balance Sheet both as regulatory assets and deferred credits. The unamortized balance of approximately $3.8 million at December 31, 1999 will be amortized through December 31, 2002. Note 12 Income taxes The components of Federal and state income tax expense are as follows (dollars in thousands):
Year Ended December 31 1999 1998 1997 Federal: Current $ 6,760 $ 5,072 $12,277 Deferred 1,587 (4,376) (5,420) Investment tax credits, net (391) (391) (391) ------- ------- ------- 7,956 305 6,466 ------- ------- ------- State: Current 1,664 1,060 3,027 Deferred 775 (1,222) (718) ------- ------- ------- 2,439 (162) 2,309 ------- ------- ------- Total Federal and state income taxes $10,395 $ 143 $ 8,775 ======= ======= ======= Federal and state income taxes charged to: Operating expenses $10,360 $ (283) $ 7,573 Other income 35 426 1,590 Extraordinary item - - (388) ------- ------- ------- $10,395 $ 143 $ 8,775 ======= ======= =======
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 1999 1998 1997 Income before income tax $26,979 $4,126 $25,115 Federal statutory rate 35% 35% 35% Federal statutory tax expense $ 9,443 $1,444 $8,790 Increases (reductions) in taxes resulting from: Dividend received deduction (790) (880) (884) Deferred taxes on plant 453 348 283 State income taxes net of Federal tax benefit 1,568 (105) 1,501 Investment credit amortization (391) (391) (391) Other 112 (273) (524) ------- ------ ------ Total income tax expense provided $10,395 $ 143 $8,775 ======= ====== ======
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 1999 1998 1997 Deferred tax assets Purchased power accrual $ 1,603 $ 3,695 $ 1,925 Accruals and other reserves not currently deductible 6,668 7,575 4,818 Deferred compensation and pension 5,402 4,295 3,655 Environmental costs accrual 4,249 3,905 1,805 ------- ------- ------- Total deferred tax assets 17,922 19,470 12,203 ------- ------- ------- Deferred tax liabilities Property, plant and equipment 50,164 51,680 51,819 Net regulatory asset 3,485 3,974 4,301 Conservation and load management expenditures 5,445 6,453 6,713 Nuclear refueling costs 3,313 1,219 534 Other 4,146 3,725 2,832 ------- ------- ------- Total deferred tax liabilities 66,553 67,051 66,199 ------- ------- ------- Net deferred tax liability $48,631 $47,581 $53,996 ======= ======= =======
The Company received an accounting order from the PSB dated September 30, 1997. This accounting order authorized the Company to defer and amortize over a 20-year period beginning January 1, 1998, approximately $2.0 million to reflect the revenue requirement level of additional deferred income tax expense resulting from the enacted Vermont Corporate income tax increase from 8.25% to 9.75% in 1997. A valuation allowance has not been recorded, as the Company expects all deferred income tax assets will be realized in the future. Note 13 Retail Rates The Company recognizes that adequate and timely rate relief is necessary if it is to maintain its financial strength, particularly since Vermont regulatory rules do not allow for changes in purchased power and fuel costs to be automatically passed on to consumers through rate adjustment clauses. The Company intends to continue its practice of periodically reviewing costs and requesting rate increases when warranted. Vermont Retail Rate Proceedings: The Company filed for a 6.6%, or $15.4 million per annum, general rate increase on September 22, 1997 to become effective June 6, 1998 to offset increasing costs of providing service. Approximately $14.3 million or 92.9% of the rate increase request was to recover scheduled contractual increases in the cost of power the Company purchases from Hydro-Quebec. At the same time, the Company also filed a request to eliminate the winter-summer rate differential and price electricity the same year-round. In response to the Company's filing, the PSB decided to appoint an independent investigator to examine the Company's decision to buy power from Hydro-Quebec. The Company made a filing with the PSB stating that the PSB as well as other parties should be barred from reviewing past decisions because the PSB already examined the Company's decision to buy power from Hydro-Quebec in a 1994 rate case in which the Company was penalized for "improvident power supply management". During February 1998, the DPS filed testimony in opposition to the Company's retail rate increase request. The DPS recommended that the PSB instead reduce the Company's then current retail rates by 2.5% or $5.7 million. The Company sought, and the PSB granted, permission to stay this rate case and to file an interlocutory appeal of the PSB's denial of the Company's motion to preclude a re-examination of the Company's Hydro-Quebec contract in 1991. The Company has argued its position before the VSC. The VSC has not yet rendered a decision and it is uncertain at this time when a decision is forthcoming. The Company filed on June 12, 1998 with the PSB for a 10.7% retail rate increase that supplanted the September 22, 1997, 6.6% rate increase request, to be effective March 1, 1999. On October 27, 1998, the Company reached an agreement with the DPS regarding the June 1998 retail rate increase request providing for a temporary rate increase in the Company's Vermont retail rates of 4.7% or $10.9 million on an annualized basis beginning with service rendered on or after January 1, 1999. The agreement was approved by the PSB on December 11, 1998. The 4.7% rate increase is subject to retroactive or prospective adjustment upon future resolution of issues arising under the VJO Power Contract presently before the VSC. The agreement temporarily disallows approximately $7.4 million for the Company's purchased power costs under the VJO Power Contract pending resolution of the issues before the VSC. As a result of the 4.7% rate increase agreement, during the fourth quarter of 1998 and 1999, the Company recorded pre-tax losses of $7.4 million and $2.9 million for disallowed purchased power costs, representing the Company's estimated under recovery of power costs, prior to further resolution, under the VJO Power Contract for calendar year 1999 and the first quarter of year 2000, respectively. If in the future, the Company is unable to increase rates to recover the temporary disallowed purchased power costs prior to further resolution under the VJO power contract or otherwise mitigate these costs, the Company would be required to record losses for any estimated future under recovery. At this time, the Company does not believe that such a loss is probable. These temporary disallowances were calculated using comparable methodology to that used by the PSB in the GMP rate case on February 28, 1998. In that case, the PSB found GMP's decision to commit to the VJO Power Contract in 1991 "imprudent" and that power purchased under it was not "used and useful." As a result, the PSB concluded that a portion of GMP's current costs should not be imposed on GMP's customers and were disallowed. GMP is appealing that rate order to the VSC. Should the Company receive a similar order from the PSB, the Company would experience a material adverse effect on its results of operations and financial condition. Assuming an unfavorable VSC ruling and depending on the methodology to determine the amount of any permanent disallowance, its future impact could be more or less than the 1999 $7.4 million temporary disallowance or the 1999 $2.9 million first quarter 2000 temporary disallowance. If the Company receives an unfavorable ruling from the VSC and the PSB subsequently issues a final rate order adopting the disallowance methodology used to determine the temporary Hydro-Quebec disallowance described above for the duration of the VJO Power Contract, the Company would not be able to recover approximately $198.2 million of power costs over the life of the contract, including $11.5 million in 2000, $11.6 million in 2001, $11.8 million in 2002, $11.9 in million 2003 and $12.1 million in 2004. In such an event, the Company would be required to take an immediate charge to earnings of approximately $198.2 million (pre-tax). Such an outcome could jeopardize the Company's ability to continue as a going concern. New Hampshire Retail Rate/Federal Court Proceedings Connecticut Valley retail rate tariffs, approved by the NHPUC, contain a FAC, and a 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 February 28, 1997 the NHPUC published its detailed Final Plan to restructure the electric utility industry in New Hampshire. Also on February 28, 1997, the NHPUC, in a supplemental order specific to Connecticut Valley, found that Connecticut Valley was imprudent for not terminating the FERC-authorized power contract between Connecticut Valley and the Company, required Connecticut Valley to give notice to cancel its contract with the Company and denied stranded cost recovery related to this power contract. Connecticut Valley filed for rehearing of the February 28, 1997 NHPUC Order. On April 7, 1997, the NHPUC issued an Order addressing certain threshold procedural matters raised in motions for rehearing and/or clarification filed by various parties, including Connecticut Valley, relative to the Final Plan and interim stranded cost orders. The April 7, 1997 Order stayed those aspects of the Final Plan that were the subject of rehearing or clarification requests and also stayed the interim stranded cost orders for the various parties, including Connecticut Valley. As such, those matters pertaining to the power contract between Connecticut Valley and the Company were stayed. The suspension of these orders was to remain in effect until two weeks following the issuance of any order concerning outstanding requests for rehearing and clarification. In an Order dated December 31, 1997 in Connecticut Valley's FAC and PPCA docket, the NHPUC found Connecticut Valley acted imprudently by not terminating the wholesale contract between Connecticut Valley and the Company, notwithstanding the stays of its February 28, 1997 Orders. The NHPUC Order further directed Connecticut Valley to freeze its current FAC and PPCA rates (other than short term rates to be paid to certain Qualifying Facilities) effective January 1, 1998, on a temporary basis, pending a hearing to determine: 1) the appropriate proxy for a market price that Connecticut Valley could have obtained if it had terminated its wholesale contract with the Company; 2) the implications of allowing Connecticut Valley to pass on to its customers only that market price; and 3) whether the NHPUC's final determination on the FAC and PPCA rates should be reconciled back to January 1, 1998 or some other date. On January 19, 1998, Connecticut Valley and the Company filed with the Court for a temporary restraining order to maintain the status quo ante by staying the NHPUC Order of December 31, 1997 and preventing the NHPUC from taking any action that (i) compromises cost-based rate making for Connecticut Valley; (ii) interferes with FERC's exclusive jurisdiction over the Company's pending application to recover wholesale stranded costs upon termination of its wholesale power contract with Connecticut Valley; or (iii) prevents Connecticut Valley from recovering through retail rates the stranded costs and purchased power costs that it incurs pursuant to its FERC-authorized wholesale rate schedule with the Company. On February 23, 1998, the NHPUC announced in a public meeting that it reaffirmed its finding of imprudence and designated a proxy market price for power at 4 cents per kWh in lieu of the actual costs incurred pursuant to the wholesale power contract with the Company. In addition, the NHPUC indicated, subject to certain conditions which were unacceptable to the companies, that it would permit Connecticut Valley to maintain its current rates pending a decision in Connecticut Valley's appeal of the NHPUC Order to the New Hampshire Supreme Court. Based on the December 31, 1997 NHPUC Order as well as the NHPUC's February 23, 1998 announcement, which resulted in the establishment of Connecticut Valley's rates on a non cost-of-service basis, Connecticut Valley no longer qualified, as of December 31, 1997, for the application of SFAS No. 71. As a result, Connecticut Valley wrote-off all of its regulatory assets associated with its New Hampshire retail business as of December 31, 1997. This write-off amounted to approximately $1.2 million on a pre-tax basis. In addition, Connecticut Valley recorded a $5.5 million pre-tax loss in 1997 for disallowed power costs. On March 20, 1998, the NHPUC issued an order which affirmed, clarified and modified various generic policy statements including the reaffirmation to establish rates on the basis of a regional average announced previously in its February 28, 1997 Order. The March 20, 1998 Order also addressed all outstanding motions for rehearings or clarification relative to the policies or legal positions articulated in the Final Plan and removed the stay covering the Company's interim stranded cost order of April 7, 1997. In addition, the March 20, 1998 Order imposed various compliance filing requirements. On April 3, 1998, the Court held a hearing on the Companies' motion for a TRO and Preliminary Injunction against the NHPUC at which time both the companies and the NHPUC presented arguments. In an oral ruling from the bench, and in a written order issued on April 9, 1998, the Court concluded that the companies had established each of the prerequisites for preliminary injunctive relief and directed and required the NHPUC to allow Connecticut Valley to recover through retail rates all costs for wholesale power requirements service that Connecticut Valley purchases from the Company pursuant to its FERC-authorized wholesale rate schedule effective January 1, 1998 until further court order. Connecticut Valley received an order from the NHPUC authorizing retail rates to recover such costs beginning in May 1998. On April 14, 1998, the NHPUC filed a notice of appeal and a motion for a stay of the Court's preliminary injunction. The NHPUC's request for a stay was denied. At the same time, the NHPUC permitted Connecticut Valley to recover in rates the full cost of its wholesale power purchases from the Company. Also, on April 3, 1998, the Court indicated its earlier TRO enjoining the NHPUC's restructuring orders applied to Connecticut Valley and prohibits the enforcement of the restructuring orders until the Court conducts a consolidated hearing and rules on the requests for permanent injunctive relief by plaintiff PSNH and the other utilities that had been allowed to intervene in these proceedings, including the Company and Connecticut Valley. The plaintiffs-intervenors thereafter filed a motion asking the Court to extend its stay of action by the NHPUC to implement restructuring and to make clear that the stay encompasses the NHPUC's order of March 20, 1998. As a result of these Court orders, Connecticut Valley's 1997 charges, described above, were reversed in the first quarter of 1998. Combined, the reversal of these charges increased 1998 net income and earnings per share of common stock by approximately $4.5 million and $.39, respectively. On April 1, 1998, the Bank notified Connecticut Valley that it was in default of the Loan Agreement between the Bank and Connecticut Valley dated December 27, 1994 and that the Bank would exercise all of its remedies from and after May 5, 1998 in the event that the violations were not cured. After reversing the 1997 write-offs described above, Connecticut Valley was in compliance with the financial covenants associated with its $3.75 million loan with the Bank. As a result, Connecticut Valley satisfied the Bank's requirements for curing the violation. On May 11, 1998 the NHPUC issued an order requiring Connecticut Valley to show cause why it should not be held in contempt for its failure to meet the compliance filing requirements of its March 20, 1998 Order. A hearing on this matter was scheduled for June 11, 1998, which was subsequently canceled because of the Court's June 5, 1998 Order, discussed below. On June 5, 1998, the Court issued an Order which denied the NHPUC's motion for a stay of the Court's preliminary injunction. The Order clearly stated that no restructuring effort in New Hampshire can move forward without the Court's approval unless all New Hampshire utilities agree to the plan. The Order suspended all involuntary restructuring efforts for all New Hampshire utilities until a hearing on the merits was conducted. The NHPUC appealed this Order to the Court of Appeals. On July 23, 1998, the NHPUC issued an order vacating that portion of its February 27, 1997 restructuring order that had directed Connecticut Valley to terminate its RS-2 wholesale power purchases from the Company. The NHPUC has expressly stated in federal court filings that its July 23, 1998 order "clarified that Connecticut Valley should not terminate the RS-2 Rate Schedule if such termination would trigger the exit fee" for which the Company has sought authorization from FERC. On November 24, 1998, Connecticut Valley filed with the NHPUC its annual FAC/PPCA rates to be effective January 1, 1999. On January 4, 1999, the NHPUC issued an Order allowing Connecticut Valley to implement the proposed FAC rate of $.008 per kWh and the proposed PPCA rate of $.01000 per kWh, on a temporary basis, effective on all bills rendered on or after January 1, 1999. In addition, the NHPUC also ordered Connecticut Valley to pay refunds plus interest to its retail customers for any overcharges collected as a result of the April 9, 1998 Federal District Court Order, should it be overturned or modified, which are included in the estimated total losses of $4.3 million discussed below. On December 3, 1998, the Court of Appeals announced its decisions on the appeals taken by the NHPUC from the preliminary injunctions issued by the Court. Those preliminary injunctions had stayed implementation of the NHPUC's plan to restructure the New Hampshire electric industry and required the NHPUC to allow Connecticut Valley to recover through its retail rates the full cost of wholesale power obtained from the Company. The Court of Appeals affirmed the preliminary injunction, issued by the Court, staying restructuring until the plaintiff utilities' claims (including those of the Company and Connecticut Valley) are fully tried. The Court of Appeals found that PSNH had sufficiently established that without the preliminary injunction against restructuring it would suffer substantial irreparable injury and that it had sufficient claims against restructuring to warrant a full trial. The Court of Appeals also affirmed the extension of the preliminary injunction to protect the other plaintiff utilities, including Connecticut Valley and the Company, although it questioned whether the other utilities had arguments as strong against restructuring as PSNH because they did not have formal agreements with the State similar to PSNH's Rate Agreement. The Court of Appeals stated that if the Court awards the utilities permanent injunctive relief against restructuring after the case is tried, then it must explain why the other utilities are also entitled to such relief. The NHPUC filed a petition for rehearing on December 17, 1998. The Court of Appeals denied the petition on January 13, 1999. The Court of Appeals also reversed the Court's preliminary injunction requiring the NHPUC to allow Connecticut Valley to recover in retail rates the full cost of the power it buys from the Company. Although the Court of Appeals found that Connecticut Valley and the Company had made a strong showing of irreparable injury to justify the preliminary injunction, it concluded that Connecticut Valley's and the Company's claims did not have a sufficient probability of success to warrant such preliminary relief. The Court of Appeals explained that the filed-rate doctrine preserving the exclusive jurisdiction of the FERC over wholesale power rates did not prevent the NHPUC from deciding whether Connecticut Valley's power purchases from the Company were prudent given alternative available sources of wholesale power. The Court of Appeals then stated that Connecticut Valley's rates could be reduced to the level prevailing on December 31, 1997. However, the Court of Appeals also stated that if the NHPUC ordered Connecticut Valley's rates to be reduced below the level existing as of December 31, 1997, "it will be time enough to consider whether they are precluded from the Court's injunction against the Final Plan or on other grounds." On December 17, 1998, Connecticut Valley and the Company filed a petition for rehearing on the grounds that the Court of Appeals had not given sufficient weight to the Court's factual findings and that the Court of Appeals had misapprehended both factual and legal issues. Connecticut Valley and the Company also asked that the entire Court of Appeals, rather than only the three-judge appellate panel that had issued the December 3 decision, consider their petition for rehearing. On January 13, 1999, the Court of Appeals denied the petition for rehearing. Connecticut Valley and the Company then requested the Court of Appeals to stay the issuance of its mandate until the companies could file a petition of certiorari to the United States Supreme Court and the Supreme Court acted on the petition. On January 22, 1999, the Court of Appeals denied the request. However, the Court of Appeals granted a 21-day stay to enable the Company to seek a stay pending certiorari from the Circuit Justice of the Supreme Court. On February 11, 1999, the Company and Connecticut Valley filed a petition for a writ of certiorari with the United States Supreme Court and a motion to stay the effect of the Court of Appeals' decision while the case was pending in the Supreme Court. The motion for a stay was addressed to Justice Souter who is responsible for such motions pertaining to the Court of Appeals for the First Circuit. On February 18, 1999, Justice Souter denied the stay pending the petition for certiorari and on April 19, 1999 the Supreme Court denied the petition for certiorari. As a result of the December 3, 1998 Court of Appeals' decision discussed above, on March 22, 1999, the NHPUC issued an Order which directed Connecticut Valley to file within five business days its calculation of the difference between the total FAC and PPCA revenues that it would have collected had the 1997 FAC and PPCA rate levels been in effect the entire year. In its Order, the NHPUC also directed Connecticut Valley to calculate a rate reduction to be applied to all billings for the period April 1, 1999 through December 31, 1999 to refund the 1998 over collection relative to the 1997 rate level. The Company estimated this amount to be approximately $2.7 million on a pre-tax basis. Connecticut Valley filed the required tariff page with the NHPUC, under protest and with reservation of all rights, on March 26, 1999 and implemented the refund effective April 1, 1999. As a result of legal and regulatory actions discussed above, Connecticut Valley no longer qualified as of December 31, 1998 for the application of SFAS No. 71, and wrote-off in the fourth quarter of 1998 all its regulatory assets associated with its New Hampshire retail business estimated at approximately $1.3 million on a pre-tax basis at December 31, 1998. In addition, Connecticut Valley also recorded estimated total losses of $4.3 million pre-tax during the fourth quarter of 1998 for disallowed power costs of $1.6 million and its refund obligations of $2.7 million. Company management, however, continues to believe that the NHPUC's actions are illegal and unconstitutional and will present its arguments in the appropriate forum. The pre-tax losses described above resulted in Connecticut Valley violating applicable covenants, which if not waived or renegotiated, would have allowed Connecticut Valley's lender the right to accelerate the repayment of a $3.75 million loan with Connecticut Valley. On March 12, 1999, Connecticut Valley was notified by the Bank that it would exercise appropriate remedies in connection with the violation of financial covenants associated with the $3.75 million loan agreement unless the violation was cured by April 11, 1999. To avoid default of this loan agreement, on April 6, 1999, pursuant to an agreement reached on March 26, 1999, the Company purchased from the Bank the $3.75 million note. On April 7, 1999, the Court ruled from the bench that the March 22, 1999 NHPUC Order requiring Connecticut Valley to provide a refund to its retail customers was illegal and beyond the NHPUC's authority. The Court also ruled that the NHPUC cannot reduce Connecticut Valley's rates below rates in effect at December 31, 1997. Accordingly, Connecticut Valley removed the rate refund from retail rates effective April 16, 1999. Lastly, the Court denied the NHPUC's motion to dissolve the injunction staying the implementation of its restructuring plan and stated its desire to rule on the pending motion for summary judgement and to conduct a hearing on the Company's request for a permanent injunction, after the NHPUC completes hearings on PSNH's stranded costs. The District Court's decision was issued as a written order on May 11, 1999. The NHPUC held a hearing on April 22, 1999 to determine whether to modify Connecticut Valley's 1999 power rates by returning the rates to the levels that were in effect on December 31, 1997. On May 17, 1999, the NHPUC issued an order requiring Connecticut Valley to set temporary rates at the level in effect as of December 31, 1997, subject to future reconciliation, effective with bills issued on and after June 1, 1999. On May 24, 1999, the NHPUC filed a petition for mandamus in the Court of Appeals challenging the Court's May 11, 1999 ruling and seeking a decision allowing the refunds as required by the NHPUC's March 22, 1999 order. The Court of Appeals denied that petition on June 2, 1999. The NHPUC immediately filed a notice of appeal in the Court of Appeals again challenging the Court's May 11, 1999 ruling. In that appeal, the Company and Connecticut Valley contend, among other things, that it is unfair for the NHPUC to direct Connecticut Valley to continue to purchase wholesale power under RS-2 in order to avoid the triggering of a FERC exit fee, but at the same time to freeze Connecticut Valley's rates at their December 31, 1997 level which does not enable Connecticut Valley to recover all of its RS-2 costs. The Court of Appeals issued a decision on January 24, 2000, which upheld the Court's preliminary injunction enjoining the Commission's restructuring plan. The decision also remanded the refund issue to the Court stating: "the district court may defer vacation of this injunction against the refund order for up to 90 days. If within that period it has decided the merits of the request for a permanent injunction in a way inconsistent with refunds, or has taken any other action that provides a showing that the Company is likely to prevail on the merits in federal court in barring the refunds, it may enter a superseding injunction against the refund order, which the Commission may then appeal to us. Otherwise, no later than the end of the 90-day period, the district court must vacate its present injunction insofar as it enjoins the Commission's refund order." The parties have also submitted motions for summary judgment to the Court, which the Court has under consideration. On March 6, 2000 the Court issued a permanent injunction mandating that the NHPUC allow Connecticut Valley to pass through to its retail customers its wholesale costs incurred under the RS-2 rates schedule with the Company. The Court also ruled that Connecticut Valley is entitled to recover those wholesale costs that the NHPUC has disallowed in retail rates since January 1, 1997. This decision is subject to implementation by the NHPUC and is subject to appeal. On June 14, 1999, PSNH and various parties in New Hampshire announced that a "Memorandum of Understanding" had been reached that is intended to result in a detailed settlement proposal to the NHPUC that would resolve PSNH's claims against the NHPUC's restructuring plan. On July 6, 1999, PSNH petitioned the Court to stay its proceedings indefinitely while the proposed settlement is reviewed and approved by the NHPUC and the New Hampshire Legislature. On July 12, 1999, the Company and Connecticut Valley objected to any stay that would allow the NHPUC's rate freeze order to remain in effect for an extended period and asked the Court to proceed with prompt hearings on its summary judgement motion and trial on the merits. On October 20, 1999 the Court heard oral arguments pertaining to the pretrial motions of the Company and the NHPUC for summary judgement and dismissal, respectively. The Court took the matters under advisement and indicated that a written order would ensue. On December 1, 1999, Connecticut Valley filed with the NHPUC a petition for a change in its FAC and PPCA rates effective on bills rendered on and after January 1, 2000. On December 30, 1999, the NHPUC denied Connecticut Valley's request to increase its FAC and PPCA rates above those in effect at December 31, 1997 subject to further investigation and reconciliation until otherwise ordered by the NHPUC. Accordingly, during the fourth quarter of 1999 Connecticut Valley recorded a pre-tax loss of $1.2 million for under collection of year 2000 power costs. FERC Proceedings The Company filed an application with the FERC in June 1997, to recover stranded costs in connection with its wholesale rate schedule with Connecticut Valley and a notice of cancellation of the Connecticut Valley rate schedule (contingent upon the recovery of the stranded costs that would result from the cancellation of this rate schedule). In December 1997, the FERC rejected the Company's proposal to recover stranded costs through the imposition of a surcharge on our transmission tariff, but indicated that it would consider an exit fee mechanism for collecting stranded costs. The FERC denied the Company's motion for a rehearing regarding the surcharge proposal, so the Company filed a request with the FERC for an exit fee mechanism to collect the stranded costs resulting from the cancellation of the contract with Connecticut Valley. The stranded cost obligation sought to be recovered through an exit fee, expressed on a net present value basis as of January 1, 2000, is approximately $44.9 million. On September 14 and 15, 1998 the Company participated in a settlement conference with an Administrative Law Judge assigned for the settlement process at the FERC and the parties to the Company's exit fee filing. During April and May 1999, nine days of hearings were held at the FERC before an Administrative Law Judge, who will determine, among other things, whether Connecticut Valley qualifies for an exit fee, and if so, the amount of Connecticut Valley's stranded cost obligation to be paid to the Company as an exit fee. The ruling of the Administrative Law Judge is expected in the first half of 2000, and the FERC will act on the judge's recommendations sometime thereafter. If the Company is unable to obtain an order authorizing the recovery of costs in connection with the June 1997 FERC filing or in the Federal Court, it is possible that the Company would be required to recognize a pre-tax loss under this contract totaling approximately $56.3 million on a pre-tax basis. The Company would also be required to write-off approximately $3.0 million (pre-tax) in regulatory assets associated with its wholesale business. However, even if the Company obtains a FERC order authorizing the updated requested exit fee, if Connecticut Valley is unable to recover its costs by increasing its rates, Connecticut Valley would be required to recognize a loss under this contract of approximately $44.9 million (pre-tax) representing future under recovery of power costs. In addition to its efforts before the Court and FERC, Connecticut Valley has initiated efforts and will continue to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC. On September 14 and 15, 1998 the Company participated in a settlement conference with an Administrative Law Judge assigned for the settlement process at the FERC and the parties to the Company's exit fee filing. An adverse resolution of these proceedings would have a material adverse effect on the Company's results of operations and cash flows. However, the Company cannot predict the ultimate outcome of this matter. Note 14 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. 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, three of which (Maine Yankee, Connecticut Yankee and Yankee Atomic) are permanently shut down, 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 Unit #3 nuclear generating plant. Until its termination on April 30, 1998, the Company purchased power and energy from Merrimack #2, pursuant to a contract dated July 16, 1966 entered into by and between VELCO and PSNH. Pursuant to the contract, as amended, VELCO agreed to reimburse PSNH, in the proportion which the VELCO quota bears to the demonstrated net capability of the plant, for all fixed costs of the unit and operating costs of the unit incurred by PSNH, which are reasonable and cost-effective for the remaining term of the VELCO contract. In early 1998, PSNH took the Merrimack Unit #2 facility off line, shut it down and commenced a maintenance outage. In February, March and April of 1998, PSNH billed VELCO for costs to complete the maintenance outage. VELCO disputes the validity of a portion of the charges on grounds that the maintenance performed at the unit was to extend the life of the Merrimack plant beyond the term of the VELCO contract and that the charges in connection with said investments were not reasonable and cost-effective for the remaining term of the VELCO contract. The Company estimates the portion of the disputed charges allocable to the Company could be as much as $.5 million on a pre-tax basis. The Company purchases power from a number of IPPs who own qualifying facilities under the Public Utility Regulatory Policies Act of 1978. These qualifying facilities produce energy using hydroelectric, biomass, and refuse-burning generation. The majority of these purchases are made from a state appointed purchasing agent who purchases and redistributes the power to all Vermont utilities. Under these long-term contracts, in 1999 the Company received 193,114 mWh of which 139,407 mWh is associated with the Vermont Electric Power Producers and 37,309 mWh with the New Hampshire/Vermont Solid Waste Plant owned by Wheelabrator Claremont Company, L.P. The Company expects to purchase approximately 205,821 mWh of small power output in each year 2000 through 2004. 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 $118.4 million. The Company is purchasing varying amounts of power from Hydro-Quebec under the VJO contract through 2016. 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 average annual amount of capacity that the Company will purchase through October 31, 2016 is 132 mW. The total commitment to purchase power under these contracts on a nominal basis is approximately $975 million net of power sellbacks over the contract term. In February 1996, the Company reached an agreement with Hydro-Quebec which lowered the 1997 cost of power by $5.8 million. As part of this agreement, the Company delivers to NEPOOL under existing firm energy contracts or joint marketing activities 54 mW of Phase II transmission capacity for a five-year period which began July 1, 1996 through June 30, 2001. In the early phase of the VJO contract, two sellback contracts were negotiated, the first delaying the purchase of 25 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 for five years during a fifteen-year term beginning in 2000. There are specific contractual step up provisions that provide that in the event any VJO member fails to meet its obligation under the contract with Hydro-Quebec, the balance of the VJO participants, including the Company, will "step up" to the defaulting party's share on a pro-rata basis. As of December 31, 1999 the Company's VJO obligation is approximately 43% or $975 million on a nominal basis over the term of the contract ending in 2016. The total VJO contract obligation on a nominal basis over the term of the contract is approximately $2.1 billion. During January 1998, a significant ice storm affected parts of New York, New England and the Province of Quebec, Canada. This storm damaged major components of the Hydro-Quebec transmission system over which power is supplied to Vermont under the VJO Power Contract with Hydro-Quebec. This resulted in a 61-day interruption of a significant portion of scheduled contractual energy deliveries into Vermont. The ice storm's effect on Hydro-Quebec's transmission system caused the VJO to examine Hydro-Quebec's overall reliability and ability to deliver energy. On the basis of that examination, the VJO determined that Hydro-Quebec has been and remains unable to make available capacity with the degree of firmness required by the VJO Power Contract. That determination has prompted the VJO to initiate an arbitration proceeding. In the arbitration, the VJO is seeking to terminate the contract, to recover damages associated with Hydro-Quebec's failure to comply with the contract, and to recover capacity payments made during the period of non-delivery. In September 1999 an initial two weeks of hearings were held dealing primarily with issues of contract interpretation. Additional hearings dealing with technical issues will be held in the second and third quarters of 2000. The Company expects a decision by the end of 2000. In accordance with a PSB Accounting Order, the Company has deferred incremental costs associated with this arbitration of approximately $2.0 million. Recovery of these costs will be determined in the next rate proceedings. 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 1999 1998 Generating plants: Wyman #4 Oil 1.78% 1978 11 $ 3,347 $ 3,347 Joseph C. McNeil Various 20.00% 1984 11 15,240 15,093 Millstone Unit #3 Nuclear 1.73% 1986 20 75,561 75,444 Highgate transmission facility 47.35% 1985 14,042 13,930 -------- -------- 108,190 107,814 Accumulated depreciation 41,201 37,934 -------- -------- $ 66,989 $ 69,880 ======= =======
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. VELCO is currently in the process of upgrading its transmission facilities in the Burlington, Vermont area where the Joseph C. McNeil generating plant is located. These transmission improvements will reduce the current need for the Joseph C. McNeil generating plant to run in support of area reliability and are expected to be in place in the second half of 2001. The Company anticipates that upon completion of the upgrade, the Joseph C. McNeil generating plant may not operate at its current capacity factor. The Company is responsible for paying its ownership percentage of decommissioning costs for Unit #3. Based on a 1997 study, the total estimated obligation at December 31, 1999 was approximately $619.5 million and the funded obligation was about $229.0 million. The Company's share for the total obligation and funded obligation was approximately $10.7 million and $4.0 million, respectively. 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 is likely to 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. As part of that process, the Company also researches the possibility of insurance coverage that could defray any such remediation expenses. Cleveland Avenue Property - 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. After completing its preliminary investigation, 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 $5.0 million. This was charged to expense in the fourth quarter of 1992. Site investigation has continued over the last several years and the Company continues to work with the State in a joint effort to develop a mutually acceptable solution. Brattleboro Manufactured Gas Facility - From the early to late 1940's, the Company owned and operated a manufactured gas facility in Brattleboro, Vermont. The Company recently received a letter from the State of New Hampshire asking the Company to conduct a scoping study in and around the site of the former facility. The Company has engaged a qualified consultant to do the scoping study and a search for other Potential Responsible Parties. At this time the Company has not finalized an estimate of its potential liability at this site. Dover, New Hampshire Manufactured Gas Facility - The Company was recently contacted by PSNH with respect to this site. PSNH alleges the Company is partially liable for remediation of this site. PSNH's allegation is premised on the fact that prior to PSNH's purchase of the facility, it was operated by Twin State Gas and Electric ("Twin State"). Twin State merged with the Company on the same day the facility was sold to PSNH. The Company is researching the underlying transactions in an effort to determine the nature and extent of any liability it may have. At this time the Company has not finalized an estimate of its potential liability at this site. 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. As of December 31, 1999, a reserve of $9.9 million has been established representing management's best estimate of the costs to remediate the sites. Dividend restrictions - The indentures relating to long-term debt, the Articles of Association and a covenant contained in the Reimbursement Agreements to the letters of credit, supporting the Company's tax exempt revenue bonds, contain certain restrictions on the payment of cash dividends on capital stock. Under the most restrictive of such provisions, approximately $29.4 million of retained earnings was not subject to dividend restriction at December 31, 1999. Under the Company's Second Mortgage Indenture, certain additional restrictions on the payment of dividends would become effective if the Company's Second Mortgage Bonds are rated below investment grade. Under the most restrictive of these provisions, approximately $16.6 million of retained earnings would not be subject to dividend restrictions at December 31, 1999. In addition, Catamount and SmartEnergy Water Heating Services, Inc., have debt instruments in place that restrict the amount of dividends on capital stock that they are able to pay. 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 2000 through 2015 and will decline thereafter. The Company's shares of the net capital cost of these facilities, totaling approximately $16.2 million, are classified in the accompanying Consolidated Balance Sheet as "Utility Plant" and "Capital lease obligations" (current and non-current). Minimum rental commitments of the Company under non-cancelable leases as of December 31, 1999, are considered minimal as the majority of the Company's leases are cancelable after one year from lease inception. Total rental expense entering into the determination of net income, consisting principally of vehicle and equipment rentals, was approximately $3.8 million for 1997, $4.0 million for 1998 and $4.2 million for 1999. Legal proceedings - On August 7, 1997, the Company and eight other non-operating owners of Unit #3 filed a demand for arbitration with Connecticut Light and Power Company and Western Massachusetts Electric Company, both NU affiliates, and lawsuits against NU and its trustees. The arbitration and lawsuits seek to recover costs associated with replacement power, operation and maintenance costs and other costs resulting from the shutdown of Unit #3. The non-operating owners claim that NU and two of its wholly owned subsidiaries failed to comply with NRC's regulations, failed to operate the facility in accordance with good operating practice and attempted to conceal their activities from the non-operating owners and the NRC. A mediator has been hired in an attempt to settle prior arbitration and the lawsuit. On September 15, 1999, NU announced that it intends to auction its nuclear generating plants, including Unit #3. We cannot predict at this time the effect of such an auction, if it occurs, on the Company or on the ongoing litigation. On October 27, 1999, NU and NEP, disclosed that NU had reached an agreement with NEP and MEC, two of the non-operating minority joint owners, to settle their claims in the arbitration and lawsuits. The settlement involves payment of fixed and contingent amounts to NEP and MEC and the inclusion of their Unit #3 interests in NU's auction of the plant. In addition, on January 28, 2000 CMP, also one of the non-operating minority joint owners, disclosed that NU and CMP had reached an agreement to settle CMP's claims in the arbitration and litigation on terms similar to the NEP and MEC settlement. The other non-operating minority joint owners, including the Company, remain active in the arbitration and lawsuits and in seeking to settle our claims against NU. In addition to the proceedings described herein, the Company is involved in litigation in the normal course of business which the Company does not believe will have a material adverse effect on the financial position or results of operations. Change of control - The Company has management continuity agreements with certain Officers which become operative upon a change in control of the Company and continue in effect until January 1, 2003. Potential severance expense under the agreements varies over time depending on officers' compensation and age at the time of the change of control. Note 15 Recent Accounting Pronouncements In June 1997, the FASB issued SFAS No. 130, Reporting Comprehensive Income, effective for fiscal years beginning after December 15, 1997. SFAS No. 130 established standards for reporting and display of comprehensive income and its components in a full set of general-purpose financial statements. It requires that an enterprise classify items of other comprehensive income by their nature in a financial statement and display the accumulated balance of other comprehensive income separately in the equity section of a statement of financial position. In 1999 and 1998 the Company recognized pre-tax minimum pension liability adjustments of $0.4 million and $0.6 million, respectively, or $0.1 million and $0.4 million net of tax, respectively. In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. In June 1999, the FASB issued Statement No. 137, Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of SFAS No. 133. This Statement establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. This Statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133, as amended, is effective for fiscal years beginning after June 15, 2000. A company may also implement this Statement as of the beginning of any fiscal quarter after issuance (that is, fiscal quarters beginning June 16, 1998 and thereafter). SFAS No. 133 cannot be applied retroactively. SFAS No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts. With respect to hybrid instruments, a company may elect to apply SFAS 133, as amended, to (1) all hybrid contracts, (2) only those hybrid instruments that were issued, acquired, or substantively modified after December 31, 1997, or (3) only those hybrid instruments that were issued, acquired, or substantively modified after December 31, 1998. The Company has not yet quantified the impacts of adopting SFAS No. 133 on the financial statements and has not determined the timing or method of the adoption of SFAS No. 133. Effective January 1, 1999, the Company adopted Emerging Issues Task Force Issue ("EITF") No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. EITF Issue 98-10 requires energy trading contracts to be recorded at fair value on the balance sheet, with the changes in fair value included in earnings. In 1999, the Company recognized a net gain of $.2 million in the accompanying Consolidated Statement of Income for its open electricity purchase and sale commitments. As discussed in Note 1, the Company decided to terminate its trading alliance with Virginia Power during the third quarter of 1999 and the Company does not intend to continue its trading operations following the maturity of its remaining open contracts in 2000. Note 16 Segment Reporting In 1998 the Company adopted SFAS No.131,"Disclosures about Segments of an Enterprise and Related Information," which establishes standards for reporting operating segments and related disclosures. It also establishes standards for related disclosures. Operating segments are defined as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company's chief operating decision making group is the Board of Directors, which is comprised of nine Directors including the Chairman of the Board and the Company's President and Chief Executive Officer. The operating segments are managed separately because each operating segment represents a different retail rate jurisdiction or offers different products or services. The Company's reportable operating segments include Central Vermont Public Service Corporation ("CV") which engages in the purchase, production, transmission, distribution and sale of electricity in Vermont; Connecticut Valley Electric Company Inc. ("CVEC") which distributes and sells electricity in parts of New Hampshire; Catamount which invests in non-regulated, energy-supply projects and SmartEnergy which pursues retail alliances to market energy and related products and services, engages in the sale of or rental of electric water heaters and has a 70% ownership interest in HSS. CVEC, while managed on an integrated basis with CV, is presented separately because of its separate and distinct regulatory jurisdiction. Other operating segments include a segment below the quantitative threshold for separate disclosure. This operating segment is C. V. Realty, Inc., a real estate company whose purpose is to own, acquire, buy, sell and lease real and personal property and interests therein related to the utility business. Segment information for 1998 and 1997 has been restated to separately present SmartEnergy which became a reportable segment in 1999. The accounting policies of the operating segments are the same as those described in the summary of significant accounting policies. Intersegment revenues include sales of purchased power to CVEC and revenues for support services to CVEC, Catamount and SmartEnergy. These intersegment sales and services for each jurisdiction are based on actual rates or current costs. The Company evaluates performance based on stand alone operating segment net income. Financial Information by industry segment for the three years ended December 31, 1999, is as follows (dollars in thousands):
Reclassification CV CVEC and Consolidating 1999 VT NH Catamount SmartEnergy Other(1) Entries Consolidated ---- -------- -------- --------- ----------- ------- ---------------- ------------ Revenues from external customers $399,268 $20,551 $ 1,316 $ 7,306 7 $ 8,633 $419,815 Intersegment revenues 11,938 - - - - 11,938 - Depreciation & other(2) 12,221 463 38 347 3 388 12,684 Reversal of estimated loss on power contracts(3) - 1,586 - - - - 1,586 Estimated loss on power contracts(3) - (1,202) - - - - (1,202) Purchased power disallowance(3) (2,859) (2,859) Reversal of purchased power disallowance(3) 7,361 - - - - - 7,361 Taxes on income 10,408 49 1,382 (1,960) 24 (457) 10,360 Operating income (loss) 24,146 491 (2,871) 2,453 (23) (455) 24,651 Equity income-affiliates(4) 2,844 - - - - - 2,844 Other income (expenses), net 2,145 5 563 (22) 69 1,513 1,247 Interest expense, net 11,880 393 101 39 - 255 12,158 Net income (loss) 18,067 102 2,061 (2,873) (773) - 16,584 Investments in affiliates, at equity 25,501 - - - - 25,501 Total assets 504,120 12,670 46,798 4,526 36,973 41,128 563,959 Capital expenditures 12,723 393 115 - - 13,231 1998 ---- Revenues from external customers $284,907 $18,933 $ 412 $ 7,184 $ - $ 7,601 $303,835 Intersegment revenues 12,755 - - - - 12,755 - Depreciation & other(2) 19,811 442 41 354 3 398 20,253 Reversal of estimated loss on power contracts(3) - 5,500 - - - - 5,500 Estimated loss on power contracts(3) - (1,586) - - - - (1,586) Purchased power disallowance(3) (7,361) - - - - - (7,361) Taxes on income (682) 399 1,914 (1,079) (3) 832 (283) Operating income (loss) 7,015 1,107 (3,689) (1,623) (20) (5,201) 7,991 Equity income-affiliates(4) 3,191 - - - - - 3,191 Other income (expenses), net 1,343 22 490 78 17 (1,511) 3,461 Interest expense, net 10,024 387 276 1 - 28 10,660 Net income (loss) 1,525 742 3,265 (1,546) (3) - 3,983 Investments in affiliates, at equity 26,142 - - - - - 26,142 Total assets 473,879 11,803 45,616 4,360 37,728 43,104 530,282 Capital expenditures 15,497 549 - - - - 16,046 1997 ---- Revenues from external customers $285,102 $19,635 $ 348 $ 1,802 $ - $ 2,155 $304,732 Intersegment revenues 10,818 - - - - 10,818 - Depreciation & other(2) 26,733 442 49 355 3 407 27,175 Estimated loss on power contracts(3) - (5,500) - - - - (5,500) Extraordinary charge, net of taxes - 811 - - - - 811 Sale of Non-Utility Assets 2,118 - 2,891 - - - 5,009 Taxes on income 9,177 (1,605) 2,097 (500) (37) 1,559 7,573 Operation income (loss) 21,364 (2,597) (4,701) (761) (60) (5,391) 18,636 Equity income-affiliates(4) 3,214 - - - - - 3,214 Other income (expenses), net 1,561 8 3,453 22 13 50 5,007 Interest expense, net 9,259 409 76 - - 38 9,706 Net income (loss) 16,880 (3,807) 4,054 (739) (48) - 16,340 Investments in affiliates, at equity 26,495 - - - - - 26,495 Total assets 481,971 11,648 41,215 2,611 356 5,861 531,940 Capital expenditures 13,220 621 - - - - 13,841 (1) Includes a segment below the quantitative threshold. (2) Includes net deferral and amortization of nuclear replacement energy and maintenance costs (included in Purchased power) and amortization of conservation and load management costs (included in Other operation expenses) in the accompanying Consolidated Statement of Income. (3) Included in Purchased power in the accompanying Consolidated Statement of Income. (4) See Note 2 herein for CV's investments in affiliates.
Note 17 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 1999 Operating revenues $98,642 $93,139 $113,221 $114,813 $419,815 Operating income $13,855 $ 1,863 $ 1,758 $ 7,175 $ 24,651 Net income $12,730 $ 416 $ 410 $ 3,028 $ 16,584 Earnings per share of common stock $1.07 $.00 $.00 $.22 $1.28 1998 Operating revenues $83,958 $66,406 $69,522 $ 83,949 $303,835 Operating income (loss) $10,679 $(4,079) $ 931 $ 460 $ 7,991 Net income (loss) $10,264 $(5,452) $ (229) $ (600) $ 3,983 Earnings (losses) per share of common stock $ .86 $ (.52) $(.06) $(.10) $ .18
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 with respect to the Company's directors is incorporated herein by this reference to "Election of Directors" and Section 16(a) Beneficial Ownership Reporting Compliance in the Proxy Statement for the 2000 Annual Meeting of Stockholders. The Executive Officers information is listed under Part I, Item 1. Definitive proxy materials will be filed with the Securities and Exchange Commission pursuant to Regulation 14A on or about March 28, 2000. Item 11. Executive Compensation. The information required by this item concerning executive compensation and directors' compensation is set forth in the sections entitled "Executive Compensation and Other Transactions", "Directors' Compensation", "Report of the Compensation Committee on Executive Compensation" and "Five-Year Shareholder Return Comparison Performance Graph" in the Proxy Statement of the Company for the 2000 Annual Meeting of Stockholders, which are being incorporated herein by reference. Definitive proxy materials will be filed with the Securities and Exchange Commission pursuant to Regulation 14A on or about March 28, 2000. 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, Executive Officers and Certain Beneficial Owners" in the Proxy Statement for the 2000 Annual Meeting of Stockholders, which is being incorporated herein by reference. Definitive proxy materials will be filed with the Securities and Exchange Commission pursuant to Regulation 14A on or about March 28, 2000. Item 13. Certain Relationships and Related Transactions. None 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, 1999 Consolidated Statement of Cash Flows, for each of the three years ended December 31, 1999 Consolidated Balance Sheet at December 31, 1999 and 1998 Consolidated Statement of Capitalization at December 31, 1999 and 1998 Consolidated Statement of Changes in Common Stock Equity for each of the three years ended December 31, 1999 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, 1999 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. Copies of any of the exhibits filed with the Securities and Exchange Commission in connection with this document may be obtained from the Company upon written request. Exhibit 3 Articles of Incorporation and By-Laws 3-1 By-Laws, as amended June 2, 1997. (Exhibit 3-1, Form 10-Q June 30, 1997, 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) 4-54 Thirty-Ninth Supplemental Indenture Dated December 29, 1997. (Exhibit 4-54, 1997 Form 10-K, File No. 1-8222) 4-55 Fortieth Supplemental Indenture Dated January 28, 1998. (Exhibit 4-55, 1997 Form 10-K, File No. 1-8222) 4-56 Credit Agreement Dated As of November 5, 1997 among Central Vermont Public Service Corporation, The Lenders Named Herein and Toronto-Dominion (Texas), Inc., as Agent. (Exhibit 10.83, 1997 Form 10-K, File No. 1-8222) 4-56.1 First Amendment to Credit Agreement Dated as of April 15, 1998 (Exhibit 10.83.1, Form 10-Q, June 30, 1998, File No. 1-8222) 4-56.2 Second Amendment to Credit Agreement Dated as of June 2, 1998 (Exhibit 10.83.2, 1997 Form 10-Q, June 30, 1998, File No. 1-8222) 4-56.3 Third Amendment to Credit Agreement Dated as of October 5, 1998 (Exhibit 4-56.3, 1998 Form 10-K, File No. 1-8222) 4-56.4 Open-End Mortgage, Security Agreement, Assignment of Rents and Leases, Fixture Filing, and Financing Statement Dated as of October 5, 1998 between the Company, as Mortgagor, in Favor of Toronto Dominion (Texas), Inc. as Collateral Agent for the Secured Parties (Exhibit 4-56.4, 1998 Form 10-K, File No. 1-8222) Fourth Amendment to Credit Agreement, dated as of May 25, 1999 (Exhibit 4-56.4, Form 10-Q, June 30, 1999, File No. 1-8222) 4-56.5 Security Agreement, dated as of October 5, 1998, between the Company and Toronto Dominion (Texas), Inc. (Exhibit 4-56.5, 1998 Form 10-K, File No. 1-8222) 4-57 Forty-First Supplemental Indenture, dated as of July 19, 1999 and resolutions establishing Series PP (Millstone) Bonds, Series QQ (Seabrook) Bonds and Series RR (East Barnet) Bonds And matters connected therewith adopted July 19, 1999 (Exhibit 4-57, Form 10-Q, September 30, 1999, File No. 1-8222) 4-58 Second Mortgage Indenture, dated as of July 15, 1999, Central Vermont Public Service Corporation to the Bank of New York, Trustee (Exhibit 4-58, Form 10-Q, September 30, 1999, File No. 1-8222) 4-59 First Supplemental Indenture to the Second Mortgage, Central Vermont Public Service Corporation to the Bank of New York, Trustee, dated as of July 15, 1999, creating an issue of Mortgage Bonds, 8-1/8% Second Mortgage Bonds due 2004 (Exhibit 4-59, Form 10-Q, September 30, 1999, File No. 1-8222) 4-60 A/B Exchange Registration Rights Agreement, dated as of July 30, 1999 by and among Central Vermont Public Service Corporation and Donaldson, Lufkin & Jenrette Securities Corporation, TD Securities (USA) Inc. (Exhibit 4-60, Form 10-Q, September 30, 1999, 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. (Exhibit 10.56.4, 1996 Form 10-K, file No. 1-8222) 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) 10.66.1 Hydro-Quebec Participation Agreement dated April 1, 1988 as amended and restated by Amendment No. 5 thereto dated October 21, 1993, among Vermont utilities participating in the purchase of electricity under the Firm Power and Energy Contract by and between Hydro-Quebec and Vermont Joint Owners of Highgate. (Exhibit 10.66.1, 1997 Form 10-Q, March 31, 1997, 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) 10.75.6 Agreement Amendment No. 5 dated November 29, 1993 (Exhibit 10.75.6, 1997 Form 10-K, File No. 1-8222) 10.75.7 Agreement Amendment No. 6 dated November 29, 1994 (Exhibit 10.75.7, 1997 Form 10-K, File No. 1-8222) 10.75.8 Agreement Amendment No. 7 dated November 29, 1995 (Exhibit 10.75.8, 1997 Form 10-K, File No. 1-8222) 10.75.9 Agreement Amendment No. 8 dated February 5, 1997 (Exhibit 10.75.9, 1997 Form 10-K, File No. 1-8222) 10.75.10 Agreement Amendment No. 9 dated February 2, 1998 (Exhibit 10.75.10, 1997 Form 10-K, File No. 1-8222) 10.83 Credit Agreement Dated As of November 5, 1997, see exhibit 4-56; 10.83.1 and 10.83.2, see exhibit 4-56.1 and 4-56.2. 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. (Exhibit 10.82, 1996 Form 10-K, File No. 1-8222) A 10.83 Management Incentive Plan for Executive Officers dated January 1, 1998 (Exhibit A10.83, Form 10-Q, March 31, 1998, File No. 1-8222) A 10.84 Officers' Change of Control Agreement dated January 1, 1998 (Exhibit 10.84, 1998 Form 10-K, File No. 1-8222) A 10.85 Officers' Supplemental Retirement and Deferred Compensation Plan as Amended and Restated Effective January 1, 1998 (Exhibit 10.85, 1998 Form 10-K, File No. 1-8222) A 10.86 1993 Stock Option Plan for Non-employee Directors (Exhibit 28 to Registration Statement, Registration 33-62100) A 10.87 1997 Stock Option Plan for Key Employees (Exhibit 4.3 to Registration Statement, Registration 333-57001) A 10.88 1997 Restricted Stock Plan for Non-employee Directors and Key Employees (Exhibit 4.3 to Registration Statement, Registration 333-57005) A 10.89 Management Incentive Plan for Executive Officers dated January 1, 1999. (Exhibit A10.89, Form 10-Q, March 31, 1999, File No. 1-8222) A 10.90 Performance Share Incentive Plan dated effective January 1, 1999. (Exhibit A10.90, Form 10-Q, June 30, 1999, File No. 1-8222) 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 24. Power of Attorney * 24.1 Powers of Attorney executed by Directors and Officers of Company 27. Financial Data Schedule (filed electronically only) (b) Reports on Form 8-K: There were no reports on Form 8-K for the quarter ended December 31, 1999. 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 7, 2000, (except with respect to the matter discussed in Note 13, as to which the date is March 6, 2000). Our audit was made for the purpose of forming an opinion on the basic financial 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 states, 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 7, 2000 (except with respect to the matter discussed in Note 13, as to which the date is March 6, 2000). Schedule II CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES Reserves Year ended December 31, 1999
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: $112,145(1) Reserve for uncollectible 310,145(2) -------- accounts receivable $2,241,796 $1,350,731 $422,290 $2,419,384(3) $1,595,433 ========== ========== ======== ========== ========== Accumulated depreciation of miscellaneous properties: Rental water heater program $3,718,075 $350,003 - $ 255,033(4) $3,813,045 Other 18,460(5) 572,908 70,087 - 94,294(6) 530,241 ---------- -------- ---------- ---------- $4,290,983 $420,090 $ 367,787 $4,343,286 ========== ======== =========== ========== Reserves shown separately: Injuries and damages reserve $ 225,580 - - - $ 225,580 ========== ========== Environmental Reserve $9,947,104 - $ 40,380(7) $ 179,170(8) $9,808,314 ========== ======== ========== ========== Company Restructuring $4,363,453 - $1,215,821(8) $3,147,632 ========== ======== ========== ========== Accumulated provision for rate refunds $2,737,345 $ 73,004 - $ 181,870(9) $2,628,479 ========== ======== ======== ========== ==========
(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) Write down of computers (6) Sale of Service Center (7) Additional Reserve (8) Expenses charged against reserve (9) Rate refund charged against reserve
Schedule II CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES Reserves Year ended December 31, 1998 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: $ 77,925(1) Reserve for uncollectible 354,950(2) ---------- accounts receivable $1,945,893 $1,126,136 $ 432,875 $1,263,108(3) $2,241,796 ========== ========== ========== ========== ========== Accumulated depreciation of miscellaneous properties: Rental water heater program $3,629,089 $ 360,158 - $ 271,172(4) $3,718,075 Other 24,918(5) 365,134 242,677 - 9,985(6) 572,908 ---------- ---------- ---------- ---------- $3,994,223 $ 602,835 $ 306,075 $4,290,983 ========== ========== ========== ========== Reserves shown separately: Injuries and damages reserve $ 225,580 - - - $ 225,580 ========== ========== Environmental Reserve $4,367,151 $ 500,000 $5,532,871(7) $ 452,918(8) $9,947,104 ========== ========== ========== ========== ========== Company Restructuring $7,659,464 $3,296,011(8) $4,363,453 ========== ========== ========== Accumulated provision for rate refunds - $2,737,345 - - $2,737,345 ========== ==========
(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) Write down of computers (6) Retirement of equipment (7) Additional Reserve (8) Expenses charged against reserve
Schedule II CENTRAL VERMONT PUBLIC SERVICE CORPORATION AND ITS WHOLLY OWNED SUBSIDIARIES Reserves Year ended December 31, 1997 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: $ 91,909(1) 415,992(2) Reserve for uncollectible 770,496(3) ---------- accounts receivable $1,132,195 $ 751,530 $1,278,397 $1,216,229(4) $1,945,893 ========== ========= ========== ========== ========== Accumulated depreciation of miscellaneous properties: Rental water heater program $3,553,149 $ 357,961 - $ 282,021(5) $3,629,089 320,811(6) Other 731,892 106,248 - 152,195(7) 365,134 ---------- --------- ---------- --------- $4,285,041 $ 464,209 $ 755,027 $3,994,223 ========== ========= ========== ========== Reserves shown separately: Injuries and damages reserve $ 225,580 - - - $ 225,580 ========== ========== Environmental Reserve $5,176,725 - $ 809,574(8) $4,367,151 ========== ========== ========== Company Restructuring - $7,720,578 - $ 61,114(8) $7,659,464 ========== ========== ==========
(1) Amount due from collection agency (2) Collections of accounts previously written off (3) Transferred from miscellaneous receivables (4) Uncollectible accounts written off (5) Retirement/Sale of rental water heaters (6) Sale of non-utility Property (7) Amortization of Customer Information Systems (8) Expenses charged against reserve 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 10,2000 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 indicated on March 10, 2000. Signature Title /s/ Robert H. Young President and Chief Executive Officer and (Robert H. Young) Director /s/ Francis J. Boyle Senior Vice President, Chief Financial (Francis J. Boyle) Officer and Treasurer (Principal Financial Officer) /s/ James M. Pennington Vice President, Controller (Principal (James M. Pennington) Accounting Officer) Frederic H. Bertrand* Chairman of the Board and Director Robert L. Barnett* Director Rhonda L. Brooks* Director Robert G. Clarke* Director Luther F. Hackett* Director Patrick . Martin* Director Mary Alice McKenzie* Director Janice L. Scites* Director By: /s/ Robert H. Young (Robert H. Young) Attorney-in-Fact for each of the persons indicated. * Such signature has been affixed pursuant to a Power of Attorney filed as an exhibit hereto and incorporated herein by reference thereto. EX-21 2 EXHIBIT 21.1 - SUBS 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 - East Barnet Hydroelectric, Inc. (a) (F1) Vermont Catamount Resources Corporation (a) (F1) Vermont Catamount Energy Corporation (a)(c) (F1) Vermont SmartEnergy Services, Inc. (a)(d) (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. (c) Catamount Energy Corporation has eleven wholly-owned subsidiaries, including nine operating in the United States, and two operating in foreign countries. (d) SmartEnergy Services, Inc. has three wholly-owned subsidiaries operating in the United States. EX-23 3 EXHIBIT 23.1 - AA EXHIBIT 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports dated February 7, 2000 (except with respect to the matter discussed in Note 13, as to which the date is March 6, 2000) included in this Form 10-K, into Central Vermont Public Service Corporation's previously filed Registration Statement Form S-3, File No. 33-39691 and Form S-8 Registration Statements, No. 33-22741, No. 33-22742, No. 33-58102, No. 33-62100, No. 333-57001, No. 333-57005 and No. 333-77217. ARTHUR ANDERSEN LLP Boston, Massachusetts March 8, 2000 EX-24 4 EXHIBIT 24.1 - POA EXHIBIT 24.1 POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that the undersigned Chief Executive Officer, Chief Financial Officer and Treasurer, and Vice President and Controller and the undersigned Directors of Central Vermont Public Service Corporation, a Vermont Corporation, which corporation proposes to file with the Securities and Exchange Commission an Annual Report on Form 10-K for the year ended December 31, 1999, under the Securities Exchange Act of 1934, as amended, does each for himself/herself and not for one another, hereby constitute and appoint Robert H. Young and Francis J. Boyle and each of them, his/her true and lawful attorneys, in his/her name, place and stead, to sign his/her name to said proposed Annual Report on Form 10-K and any and all amendments thereto, and to cause the same to be filed with the Securities and Exchange Commission, it being intended to grant and hereby granting to said individuals, and each of them, full power and authority to do and perform any act and thing necessary and proper to be done in the premises as fully and to all intents and purposes as the undersigned could do regarding the preparation, execution, filing of Form 10-K. IN WITNESS WHEREOF, each of the undersigned has hereunto set their hand as of the 7th day of February, 2000. /s/ Robert H. Young /s/ Frederic H. Bertrand Robert H. Young Frederic H. Bertrand Chief Executive Officer and Director Chairman of the Board of Directors /s/ Francis J. Boyle /s/ Robert L. Barnett Francis J. Boyle Robert L. Barnett, Director Chief Financial Officer and Treasurer /s/ James M. Pennington /s/ Rhonda L. Brooks James M. Pennington Rhonda L. Brooks, Director Vice President and Controller /s/ Robert G. Clarke Robert G. Clarke, Director /s/ Luther F. Hackett Luther F. Hackett, Director /s/ Patrick J. Martin Patrick J. Martin, Director /s/ Mary Alice McKenzie Mary Alice McKenzie, Director /s/ Janice L. Scites Janice L. Scites, Director EX-27 5 EXHIBIT 27 - FDS
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). YEAR DEC-31-1999 DEC-31-1999 PER-BOOK 314,732 73,283 106,160 69,784 0 563,959 66,556 45,340 72,371 184,021 17,000 8,054 155,251 0 0 0 16,688 0 15,060 1,094 166,791 563,959 419,815 10,360 384,804 395,164 24,651 4,091 28,742 12,158 16,584 1,862 14,722 10,099 8,710 31,232 1.28 1.28
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