-----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, BHeBkirWtD1MfMpbonjPTyxyxJ17lGvfV2ZgwjObNpjlEBZJWEj12NfqloGGtj5U YuoTsbt6+eTyCLzBBB+cVg== 0000018808-99-000030.txt : 19990624 0000018808-99-000030.hdr.sgml : 19990624 ACCESSION NUMBER: 0000018808-99-000030 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990331 FILED AS OF DATE: 19990513 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-Q SEC ACT: SEC FILE NUMBER: 001-08222 FILM NUMBER: 99620367 BUSINESS ADDRESS: STREET 1: 77 GROVE ST CITY: RUTLAND STATE: VT ZIP: 05701 BUSINESS PHONE: 8027732711 10-Q 1 FORM 10-Q PERIOD ENDING 3/31/99 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 Form 10-Q x QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 1999 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) Incorporated in Vermont 03-0111290 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 77 Grove Street, Rutland, Vermont 05701 (Address of principal executive offices) (Zip Code) 802-773-2711 (Registrant's telephone number, including area code) (Former name, former address and former fiscal year, if changed since last report) 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 the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of April 30, 1999 there were outstanding 11,463,019 shares of Common Stock, $6 Par Value. CENTRAL VERMONT PUBLIC SERVICE CORPORATION Form 10-Q Table of Contents Page PART I. FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Statement of Income and Retained Earnings for the three months ended March 31, 1999 and 1998 3 Consolidated Balance Sheet as of March 31, 1999 and December 31, 1998 4 Consolidated Statement of Cash Flows for the three months ended March 31, 1999 and 1998 5 Notes to Consolidated Financial Statements 6-14 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 15-34 PART II. OTHER INFORMATION 35-36 SIGNATURE 37
CENTRAL VERMONT PUBLIC SERVICE CORPORATION PART I - FINANCIAL INFORMATION Item 1. Financial Statements CONSOLIDATED STATEMENT OF INCOME AND RETAINED EARNINGS (Dollars in thousands, except per share amounts) (Unaudited) Three Months Ended March 31 1999 1998 Operating Revenues $98,642 $83,958 Operating Expenses Operation Purchased power 50,035 39,706 Production and transmission 5,000 5,588 Other operation 12,039 11,434 Maintenance 2,884 3,852 Depreciation 4,185 4,227 Other taxes, principally property taxes 3,087 3,040 Taxes on income 7,557 5,432 ------- ------- Total operating expenses 84,787 73,279 ------- ------- Operating Income 13,855 10,679 ------- ------- Other Income and Deductions Equity in earnings of affiliates 640 732 Allowance for equity funds during construction 10 17 Other income, net 1,059 578 Provision for income taxes (245) 10 Total other income and deductions, net 1,464 1,337 ------- ------- Total Operating and Other Income 15,319 12,016 ------- ------- Interest Expense Interest on long-term debt 2,093 2,531 Other interest 503 103 Allowance for borrowed funds during construction (7) (9) ------- ------- Total interest expense, net 2,589 2,625 ------- ------- Net Income Before Extraordinary Credit 12,730 9,391 Extraordinary Credit Net of Taxes - 873 ------- ------- Net Income 12,730 10,264 Retained Earnings at Beginning of Period 67,748 75,841 ------- ------- 80,478 86,105 Cash Dividends Declared Preferred stock 465 486 Common stock - 6 ------- ------- Total dividends declared 465 492 ------- ------- Retained Earnings at End of Period $80,013 $85,613 ======= ======= Earnings Available For Common Stock $12,265 $ 9,778 Average Shares of Common Stock Outstanding 11,461,131 11,423,951 Basic and Diluted Share of Common Stock: Earnings before extraordinary credit $1.07 $.78 Extraordinary credit - .08 ----- ---- Earnings Per Basic and Diluted Share of Common Stock $1.07 $.86 ----- ---- Dividends Paid Per Share of Common Stock $ .22 $.22 The accompanying notes are an integral part of these consolidated financial statements.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION CONSOLIDATED BALANCE SHEET (Dollars in thousands) March 31 December 31 1999 1998 Assets Utility Plant, at original cost $469,883 $469,204 Less accumulated depreciation 164,526 160,666 -------- -------- 305,357 308,538 Construction work in progress 11,272 10,461 Nuclear fuel, net 1,417 948 -------- -------- Net utility plant 318,046 319,947 -------- -------- Investments and Other Assets Investments in affiliates, at equity 25,957 26,142 Non-utility investments 37,620 35,896 Non-utility property, less accumulated depreciation 2,806 2,920 -------- -------- Total investments and other assets 66,383 64,958 -------- -------- Current Assets Cash and cash equivalents 30,703 10,051 Special deposits 426 424 Accounts receivable, less allowance for uncollectible accounts ($2,206 in 1999 and $2,242 in 1998) 29,078 29,224 Unbilled revenues 14,454 18,677 Materials and supplies, at average cost 3,616 3,746 Prepayments 2,041 1,881 Other current assets 6,100 9,768 -------- -------- Total current assets 86,418 73,771 -------- -------- Regulatory Assets 63,745 66,719 -------- -------- Other Deferred Charges 5,047 4,887 -------- -------- Total Assets $539,639 $530,282 ======== ======== Capitalization and Liabilities Capitalization Common stock, $6 par value, authorized 19,000,000 shares; outstanding 11,785,848 shares $ 70,715 $ 70,715 Other paid-in capital 45,324 45,318 Accumulated other comprehensive income (365) (365) Treasury stock (324,717 shares, at cost) (4,234) (4,234) Retained earnings 80,013 67,748 -------- -------- Total common stock equity 191,453 179,182 Preferred and preference stock 8,054 8,054 Preferred stock with sinking fund requirements 17,000 18,000 Long-term debt 90,071 90,077 Capital lease obligations 15,871 16,141 -------- -------- Total capitalization 322,449 311,454 -------- -------- Current Liabilities Short-term debt 37,000 37,000 Current portion of long-term debt and preferred stock 7,773 6,773 Accounts payable 6,680 11,589 Accounts payable - affiliates 10,269 11,784 Accrued income taxes 7,974 2,975 Dividends declared 465 2,521 Nuclear decommissioning costs 4,820 4,820 Disallowed purchased power costs 5,520 7,361 Other current liabilities 20,325 17,403 -------- -------- Total current liabilities 100,826 102,226 -------- -------- Deferred Credits Deferred income taxes 47,767 47,581 Deferred investment tax credits 6,733 6,831 Nuclear decommissioning costs 22,185 23,239 Other deferred credits 39,679 38,951 -------- -------- Total deferred credits 116,364 116,602 -------- -------- Total Capitalization and Liabilities $539,639 $530,282 ======== ======== The accompanying notes are an integral part of these consolidated financial statements.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (Dollars in thousands) (Unaudited) Three Months Ended March 31 1999 1998 Cash Flows Provided (Used) By Operating Activities Net income $12,730 $10,264 Adjustments to reconcile net income to net cash provided by operating activities Equity in earnings of affiliates (745) (732) Dividends received from affiliates 928 618 Equity in earnings of non-utility investments (1,372) (1,659) Distribution of earnings from non-utility investments 815 1,184 Extraordinary credit - (1,293) Depreciation 4,185 4,227 Deferred income taxes and investment tax credits 412 1,723 Allowance for equity funds during construction (10) (17) Net deferral and amortization of nuclear refueling replacement energy and maintenance costs 2,185 (1,345) Amortization of conservation and load management costs 1,314 1,755 Amortization of capital leases 270 270 Decrease in accounts receivable and unbilled revenues 4,235 4,482 Increase (decrease) in accounts payable (6,130) 3,364 Increase (decrease) in accrued income taxes 4,999 (2,171) Change in other working capital items 5,289 (3,531) Other, net (669) (513) ------- ------- Net cash provided by operating activities 28,436 16,626 ------- ------- Investing Activities Construction and plant expenditures (3,283) (3,242) Conservation & load management expenditures (496) (568) Return of capital 47 47 Non-utility investments (1,250) (100) Other investments, net (4) (156) ------- ------- Net cash used for investing activities (4,986) (4,019) ------- ------- Financing Activities Short-term debt, net - (400) Long-term debt, net (6) (5) Common and preferred dividends paid (2,522) (2,518) Reduction in capital lease obligations (270) (270) Sale of treasury stock - 29 ------- ------- Net cash used for financing activities (2,798) (3,164) ------- ------- Net Increase in Cash and Cash Equivalents 20,652 9,443 Cash and Cash Equivalents at Beginning of Period 10,051 16,506 ------- ------- Cash and Cash Equivalents at End of Period $30,703 $25,949 ======= ======= Supplemental Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) $ 778 $ 586 Income taxes (net of refunds) $ 2,390 $ 5,851 The accompanying notes are an integral part of these consolidated financial statements.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS March 31, 1999 Note 1 - Accounting Policies The Company's significant accounting policies are described in Note 1 of Notes to Consolidated Financial Statements included in its 1998 Annual Report on Form 10-K filed with the Securities and Exchange Commission. For interim reporting purposes, the Company follows these same basic accounting policies but considers each interim period as an integral part of an annual period. RECLASSIFICATION Certain reclassifications have been made to prior year Consolidated Statement of Cash Flows to conform with the 1999 presentation. The financial information included herein is unaudited; however, such information reflects all adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair statement of results for the interim periods. Note 2 - 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 (PRPs). At this time the Company has not finalized an estimate of its potential liability at this site. PCB, INC. In August 1995, the Company received an Information Request from the EPA pursuant to a Superfund investigation of two related sites, located in Kansas and in Missouri (the Sites). During the mid-1980's, these Sites, operated by PCB Treatment, Inc., received materials containing PCBs from hundreds of sources, including the Company. According to the EPA, more than 1,200 parties have been identified as PRPs. The Company has complied with the information request and will monitor EPA activities at the Sites. In December 1996, the Company received an invitation to join a PRP steering committee. The Company has not yet decided whether joining that committee would be in its best interest. That committee has estimated the Company's pro rata share of the waste sent to the Sites to be 0.42%. The committee estimates that the Sites' remediation will cost between $5 million and $40 million. Based on this information, the Company does not believe that the Sites represent the potential for a material adverse effect on its financial condition or results of operations. The Company 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. A reserve of $9.9 million has been established representing management's best estimate of the costs to remediate the sites. Note 3 - Retail Rates Vermont: The Company's practice of reviewing costs periodically will continue and rate increases will be requested when warranted. 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. 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. Several parties in the Company's rate case sought to challenge the Company's decision in 1991 to "lock-in" its participation in its power purchase agreement with Hydro-Quebec as one of 14 members of the Vermont Joint Owners (VJO) claiming that the decision of the Company to commit to the power contract in 1991 was imprudent and that power now purchased pursuant to that agreement is not "used and useful." The parties have also claimed that the Company has not met a condition of the PSB's prior approval of the contract, requiring that the Company obtain all cost effective Demand Side Management. In response, the Company filed a motion asking the PSB to rule that any prudence and used and useful issues were resolved in prior proceedings and that the PSB is precluded from again trying the Company on those issues. On April 17, 1998, the PSB issued an order generally denying the Company's motion. Given the fact that the PSB had severely penalized another VJO member, Green Mountain Power Corporation (GMP), in an Order dated February 27, 1998, after finding that its decision to lock-in the Hydro-Quebec contract was imprudent and the power purchased pursuant to that lock-in was not used and useful, the Company concluded that it was necessary to have the so-called preclusion issue reviewed by the Vermont Supreme Court (VSC) before the PSB issues a final order in the Company's 6.6% rate increase request. As such, the Company and other parties requested that the PSB consent to the filing of an interlocutory appeal of the PSB's decision and to a stay of the rate case pending review by the VSC. The Company further agreed to toll the statutory period of time in which the PSB must act on a rate request, while the matter is in appeal. The resolution of this matter by the VSC is likely to involve a remand to the PSB. 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. In an effort to mitigate eroding earnings and cash flow prospects during the VSC review process, on June 12, 1998 the Company filed with the PSB a request for a 10.7% rate increase ($24.9 million of annualized revenues) effective March 1, 1999. This rate case proceeding supplanted the 6.6% rate increase request referenced above 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 Vermont Department of Public Service (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 common equity in its Vermont retail business at 11% before disallowances in connection with the Hydro-Quebec Contract. 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. The Company anticipates a ruling by the VSC on the Hydro-Quebec Contract issues before the end of 1999. The agreement incorporates a disallowance of approximately $7.4 million for the Company's purchased power costs under the Hydro-Quebec Contract while the VSC reviews the PSB denial of the Company's claim that the PSB is precluded from again trying the Company on certain Hydro-Quebec Contract issues discussed above. This $7.4 million disallowance was calculated using the same formula as contained in the rate order issued by the PSB in the GMP rate case on February 28, 1998. Upon approval of the agreement by the PSB, the Company, during the fourth quarter of 1998, recorded a loss of $7.4 million on a pre-tax basis for disallowed purchased power costs representing the Company's estimated under recovery of power costs under the Hydro-Quebec Contract. If the Company receives an unfavorable ruling from the VSC, and the PSB issues a rate order adopting the methodology used to determine the temporary Hydro-Quebec disallowance for the duration of the Hydro-Quebec Contract, approximately $205.0 million of power costs to be incurred under that contract would not be recoverable in rates. This would result in an immediate charge to earnings of $205.0 million on a pre-tax basis once such outcome became probable. Such an outcome would jeopardize the ability of the Company to continue as a going concern. New Hampshire: In an Order dated December 31, 1997 in Connecticut Valley Electric Company Inc.'s (Connecticut Valley) Fuel Adjustment Clause (FAC) and Purchased Power Cost Adjustment (PPCA) docket, the New Hampshire Public Utilities Commission (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 Federal District Court (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 the Federal Energy Regulatory Commission's (FERC) 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 Statement of Financial Accounting Standards (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 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 (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 Public Service Company of New Hampshire (PSNH) and the other utilities that have 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, Citizens Bank of New Hampshire (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 United States First Circuit Court of Appeals (Court of Appeals). 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 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 the refund effective April 1, 1999. On April 7, 1999, the Court ruled from the bench that the March 22, 1999 NHPUC Order which mandated Connecticut Valley to provide a refund to its retail customers was illegal and the imposition of the refund went beyond the authority of the NHPUC. 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 remaining stay of restructuring activities and indicated 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 Company expects the hearings on the permanent injunction will take place later this year. 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. No order has been issued on this matter. 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 increase 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 Court Order, which are included in the estimated total losses of $4.3 million discussed below. As a result of legal and regulatory actions discussed above, Connecticut Valley no longer qualifies for the application of SFAS No. 71, and wrote-off all its regulatory assets associated with its New Hampshire retail business estimated at approximately $1.3 million on a pre-tax basis. In addition, Connecticut Valley recorded estimated total losses of $4.3 million pre-tax for disallowed power costs of $1.6 million and 1998 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 allow 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 June 25, 1997, the Company filed with the FERC a notice of termination of its power supply contract with Connecticut Valley, conditional upon the Company's request to impose a surcharge on the Company's transmission tariff to recover the stranded costs that would result from the termination of its contract with Connecticut Valley. The amount requested was $44.9 million plus interest at the prime rate to be recovered over a ten-year period. In its Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected the Company's proposed stranded cost surcharge mechanism but indicated that it would consider an exit fee mechanism for collecting stranded costs. The FERC also rejected the Company's arguments concerning the applicability of stated FERC policies regarding retail stranded costs, multi-state regulatory gaps and the implications of state restructuring initiatives. The Company filed a motion seeking rehearing of the FERC's December 18, 1997 Order which was denied. Thereafter, the Company appealed the FERC decision to the Court of Appeals for the District of Columbia circuit. In addition, and in accordance with the December 18, 1997 FERC Order, on January 12, 1998 the Company filed a request with the FERC for an exit fee mechanism to collect $44.9 million in a lump sum, or in installments with interest at the prime rate over a ten-year period, to cover the stranded costs resulting from the cancellation of Connecticut Valley's power contract with the Company. On March 11, 1998, the FERC issued an order accepting for filing the Company's request for an exit fee effective March 14, 1998, and set hearings to determine: whether Connecticut Valley will become an unbundled transmission customer of the Company, the Company's expectation as to the period of time it would serve Connecticut Valley, and the allowable amount of the exit fee. The FERC also rejected the Company's June 25, 1997 notice of termination indicating that the notice can be resubmitted when the power contract is proposed to be terminated. On April 28, 1998, the Company filed its case-in-chief before the FERC updating the amount of the exit fee to $54.9 million in a lump sum, describing 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. Had termination taken effect on January 1, 1998 this expectation period would have equaled nineteen years. On August 4 and 5, 1998 Phase 1 hearings were held at the FERC on the issue of whether Connecticut Valley will become an unbundled transmission customer of the Company. Subsequent to those hearings, the parties agreed to go on to hearings on the Phase 2 issues (addressing the allowable amount of the exit fee) without a preliminary determination from the Administrative Law Judge or the FERC on the Phase 1 issues. The Company submitted supplemental testimony on Phase 2 issues in December 1998 and the hearings were completed on May 10, 1999. From April 27 through May 10, 1999, nine days of hearings were held at the FERC on the Phase II issues of (1) whether the Company has overcome the rebuttable presumption that its expectation to provide wholesale power service to Connecticut Valley extends beyond the one year termination notice provision contained in its otherwise automatically renewing FERC regulated rate schedule and (2) if rebutted, the amount of Connecticut Valley's stranded cost obligation to be paid the Company as an exit fee. During the course of the hearings, the Company reached a partial stipulation with the parties that resulted in revision of its requested exit fee to approximately $48.0 million had termination taken place on January 1, 1999. If the Company is unable to obtain an order authorizing the full recovery amount of the exit fee, or other appropriate mechanism, the Company would be required to recognize a loss under this contract totaling approximately $60.0 million on a pre-tax basis. Furthermore, the Company would be required to write-off approximately $4.0 million in regulatory assets associated with its wholesale business on a pre-tax basis. Conversely, even if the Company obtains a FERC order authorizing the updated requested exit fee, Connecticut Valley would be required to recognize a loss under this contract of approximately $48.0 million on a pre-tax basis unless Connecticut Valley has obtained an order by the NHPUC or other appropriate body directing the recovery of those costs in Connecticut Valley's retail rates. Either of these reasonably possible outcomes could occur during calendar year 1999. The Company 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, cash flows, and ability to obtain capital at competitive rates. However, the Company cannot predict the ultimate outcome of this matter. Note 4 - Segment Reporting The Company adopted SFAS No.131,"Disclosures about Segments of an Enterprise and Related Information," effective for financial statements for periods beginning after December 15, 1997. 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 (Central Vermont) which engages in the purchase, production, transmission, distribution and sale of electricity in Vermont; Connecticut Valley Electric Company Inc. (Connecticut Valley) which distributes and sells electricity in parts of New Hampshire; and Catamount Energy Corporation (Catamount) which invests in non-regulated, energy-supply projects. Connecticut Valley, while managed on an integrated basis with Central Vermont, is presented separately because of its separate and distinct regulatory jurisdiction. Other operating segments include segments below the quantitative threshold for separate disclosure. These operating segments are SmartEnergy Services, Inc. which markets energy-saving products, pursues retail alliances to market energy and related products and services and engages in the sale of or rental of electric water heaters, and 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. The accounting policies of the operating segments are the same as those described in Note 1 to Consolidated Financial Statements included in its 1998 Annual Report on Form 10-K filed with the Securities and Exchange Commission. Intersegment revenues include sales of purchased power to Connecticut Valley and revenues for support services to Connecticut Valley, 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 months ended March 31, 1999 and 1998, is as follows (dollars in thousands):
Reclassifications Central Vermont Connecticut Valley All & Consolidating 1999 Vermont New Hampshire Catamount Other(1) Entries Consolidated ---- --------------- ------------------ --------- -------- ---------------- ------------ Revenues from external customers $ 92,259 $ 6,385 $ 129 $ 2,322 $2,453 $ 98,642 Intersegment revenues 3,323 3,323 - Net income (loss) 12,211 53 605 (139) - 12,730 Total assets 482,666 12,169 43,861 5,963 5,020 539,639 1998 Revenues from external customers $ 78,294 $ 5,664 $ 66 $ 472 $ 538 $ 83,958 Intersegment revenues 3,443 3,443 - Net income (loss) before extraordinary credit 5,508 3,593 738 (448) - 9,391 Net income (loss) 5,508 4,466 738 (448) - 10,264 Total assets 484,794 14,747 40,991 2,741 5,974 537,299 (1) Includes segments below the quantitative threshold for separate disclosure.
Note 5 - Investment in Vermont Yankee Nuclear Power Corporation The Company accounts for its investment in Vermont Yankee using the equity method. Summarized financial information for Vermont Yankee Nuclear Power Corporation follows: Three Months Ended March 31 1999 1998 Operating revenues $43,777 $51,170 Operating income $ 3,786 $ 3,760 Net income $ 1,656 $ 1,702 Company's equity in net income $518 $510 CENTRAL VERMONT PUBLIC SERVICE CORPORATION Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS March 31, 1999 Earnings Overview Net income and earnings per share of common stock for the quarter ended March 31, 1999 were $12.7 million and $1.07 compared to $10.3 million and $.86 for the corresponding period last year. Improved net income and earnings per share of common stock for 1999 reflect the postive impact of a 4.7% temporary Vermont retail rate increase effective with service rendered January 1, 1999 ($3.0 million after-tax, or $.26 per share of common stock) as well as a 3.7% increase in retail MWH sales. Other factors affecting results for 1999 are described in Results of Operations below. First quarter 1998 reflects the positive impact of reversing Connecticut Valley Electric Company Inc.'s (Connecticut Valley) fourth quarter 1997 after-tax charges of $4.5 million, or $.39 per share of common stock. RESULTS OF OPERATIONS The major elements of the Consolidated Statement of Income are discussed below. Operating Revenues and MWH Sales A summary of MWH sales and operating revenues for the three months ended March 31, 1999 and 1998 (and the related percentage changes from 1998) is set forth below:
Three Months Ended March 31 Percentage Percentage MWH Increase Revenues (000's) Increase 1999 1998 (Decrease) 1999 1998 (Decrease) Residential 274,697 264,461 3.9 $38,693 $35,177 10.0 Commercial 235,320 228,432 3.0 30,324 27,462 10.4 Industrial 115,181 109,888 4.8 11,276 10,095 11.7 Other retail 1,538 1,802 (14.7) 439 483 (9.1) --------- ------- ------- ------- Total retail sales 626,736 604,583 3.7 80,732 73,217 10.3 --------- ------- ------- ------- Resale sales: Firm 914 674 35.6 42 19 121.1 Entitlement 99,368 85,012 16.9 4,731 4,984 (5.1) Other 487,958 170,089 186.9 12,648 4,604 174.7 --------- ------- ------- ------- Total resale sales 588,240 255,775 130.0 17,421 9,607 81.3 --------- ------- ------- ------- Other revenues - - - 489 1,134 (56.9) --------- ------- ------- ------- Total sales 1,214,976 860,358 41.2 $98,642 $83,958 17.5 ========= ======= ======= =======
Retail MWH sales for the first quarter of 1998 increased 3.7% compared to the first quarter of 1998 reflecting a return to normal winter weather compared to 1998. Retail revenues increased $7.5 million, or 10.3% compared to last year. This variance is attributable to a $2.6 million impact of higher MWH sales in the first quarter of 1999 as compared to the first quarter of 1998 and $4.9 million resulting from the 4.7% temporary Vermont retail rate increase discussed above. For the first quarter of 1999, entitlement MWH sales increased 16.9% while related revenues decreased 5.1% compared to the same period last year. These variances result from the Vermont Yankee extended refueling outage in 1998. Other resale sales increased 317,869 MWH and other resale revenues increased $8.0 million for the first quarter of 1999 primarily as a result of increased level of activity by the Company through its alliance with Virginia Power in jointly supplying wholesale power in New England. Other revenues decreased for the first quarter of 1999 due to a provision for rate refunds of $.3 million related to a December 3, 1998 United States Court of Appeals' (Court of Appeals) decision and January 4, 1999 New Hampshire Public Utilities Commission (NHPUC) order discussed below, and to lower revenues associated with transmission interconnection agreements partially offset by increased pole attachment rentals. Net Purchased Power and Production Fuel Costs The net cost components of purchased power and production fuel costs for the three months ended March 31, 1999 and 1998 are as follows (dollars in thousands):
1999 1998 Units Amount Units Amount Purchased and produced: Capacity (MW) 1,084 $22,484 569 $20,441 Energy (MWH) 1,175,499 27,551 836,276 19,265 ------- ------- Total purchased power costs 50,035 39,706 Production fuel (MWH) 115,414 616 75,075 515 ------- ------- Total purchased power and production fuel costs 50,651 40,221 Entitlement and other resale sales (MWH) 587,326 17,379 255,101 9,588 ------- ------- Net purchased power and production fuel costs $33,272 $30,633 ======= =======
Net purchased power and production fuel costs increased $2.6 million, or 8.6% for the first quarter of 1999 compared to the first quarter of 1998. The 1999 first quarter reflects the positive impact of $1.8 million (pre-tax) as the result of disallowed Hydro-Quebec power costs during the fourth quarter of 1998. The 1998 first quarter reflects the positive impact of reversing Connecticut Valley's fourth quarter 1997 charge of $5.5 million pre-tax. Absent these non-recurring items, net purchased power and production fuel costs decreased $1.0 million. The Company owns and operates 20 hydroelectric generating units and two gas turbines and one diesel peaking unit with a combined capability of 73.7 MW. The Company has equity ownership interests in four nuclear generating companies: Vermont Yankee, Maine Yankee, Connecticut Yankee and Yankee Atomic. In addition, the Company maintains joint-ownership interests in Joseph C. McNeil, a 53 MW wood, gas and oil-fired unit; Wyman #4, a 619 MW oil-fired unit; and Millstone Unit #3, an 1149 MW nuclear unit. 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 Vermont Electric Power Company, Inc. (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 that the portion of the disputed charges allocable to the Company could be as much as $1.0 million on a pre-tax basis. NUCLEAR MATTERS The Company maintains a 1.7303% joint-ownership interest in the Millstone 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 owns 2%, 3.5% and 31.3% equity interest in Maine Yankee, Yankee Atomic and Vermont Yankee, respectively. Millstone Unit #3 Millstone Unit #3 (Unit #3) resumed operation in June 1998, accordingly, production fuel costs increased for the first quarter of 1999 compared to the first quarter of 1998. 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 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. 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 Federal Energy Regulatory Commission (FERC) which, if approved by the FERC, would result in the settlement of 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. Approval of the settlement would also resolve 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 would 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. 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 $14.9 million, $9.7 million and $2.4 million, respectively, at March 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 decommissioning costs (current and non-current). Although the estimated costs of decommissioning are subject to change due to changing technologies and regulations, the Company expects that the nuclear generating companies' liability for decommissioning, including any future changes in the liability, will be recovered in their rates over their operating or license lives. The 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. Vermont Yankee The Design Basis Documentation project (Project) initiated by Vermont Yankee during 1996 is expected to be completed by the end of 2000. The Company's 35% share of the total cost for this Project is expected to be about $6.2 million. Such costs will be deferred by Vermont Yankee and amortized over the remaining license life of the plant. On February 25, 1999, the Board of Directors of Vermont Yankee granted an exclusive right to AmerGen Energy Co. to conduct due diligence and negotiate a possible agreement to purchase the assets of Vermont Yankee. Production and Transmission As a result of a settled transmission contract dispute with Hydro-Quebec, production and transmission expenses decreased $.6 million for the first quarter of 1999 compared to the first quarter of 1998. Other Operation Principally due to increased legal and regulatory expenses, other operation expenses increased $.6 million for the first quarter of 1999 compared to the first quarter of 1998. Maintenance The decrease in maintenance expenses of about $1.0 million results primarily from the severe ice storm in January 1998. Income Taxes Federal and state income taxes fluctuate with the level of pre-tax earnings. The increase in total income tax expense for the first quarter of 1999 results primarily from an increase in pre-tax earnings for the period. Other Income and Deductions The increase in other income, net for the 1999 first quarter results primarily from lower expenditures related to SmartEnergy Service, Inc., a wholly owned non-utility subsidiary of the Company. Interest Expense Due to the retirement of long-term debt in December 1998, interest expense on long-term debt decreased for the 1999 first quarter compared to the first quarter of 1998. Other interest expense increased for the 1999 first quarter due to an increase in outstanding short-term borrowings. Extraordinary Credit The 1998 extraordinary credit net of taxes of $.9 million represents a reversal of a charge of a like amount taken in the fourth quarter of 1997. 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 flow provided by operating activities generated $28.4 million and $16.6 million for the three months ended March 31, 1999 and 1998, respectively. The increase is primarily due to improved cash earnings, lower tax payments and the extended refueling outage at the Vermont Yankee Nuclear Power Plant during 1998. The Company ended the first three months of 1999 with cash and cash equivalents of $30.7 million, an increase of $20.7 million from the beginning of the year. The increase in cash for the first three months of 1999 was the result of $28.4 million provided by operating activities, offset by $5.0 million used for investing activities and $2.8 million used for financing activities. Operating Activities - Net income, depreciation and deferred income taxes and investment tax credits provided $17.3 million. About $11.1 million of cash was provided by working capital and other operating activities. Investing Activities - Construction and plant expenditures consumed approximately $3.3 million, while $1.7 million was used for C&LM programs and non-utility investments. Financing Activities - Dividends paid on common stock were $2.5 million and reduction in capital lease obligations required $.3 million. The level of short-term borrowings fluctuates based on seasonal corporate needs, the timing of long-term financings and market conditions. The Company has a $50.0 million revolving credit facility with a group of banks maturing on June 1, 1999, of which $25.0 million was outstanding at March 31, 1999. The Company expects that borrowings will be $25.0 million at June 1, 1999. Additionally, the Company must rollover an aggregate of $16.3 million of letters of credit between December 1999 and May 2000. In addition, the Company has a $12.0 million accounts receivable facility which matures in November 1999. The Company has agreed with its lenders to extend the revolving credit facility to June 1, 2000, but with a reduced credit limit of $40.0 million. An agreement has also been reached to extend the renewal dates of the letters of credit to also be June 1, 2000. The Company expects to close the extended revolving credit facility and letters of credit during May 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. 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 Credit Watch with negative implications. 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, which could be resolved in 1999. Adequate rate relief and successful mitigation of high power costs through contract renegotiations or other methods are essential to stabilizing the ratings." 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." Current credit ratings by Duff & Phelps remain at 'BBB' (Triple-B) for first mortgage bonds and 'BBB-' (Triple-B-Minus) for preferred stock. Current credit ratings of the Company's securities by Duff & Phelps and Standard & Poor's are as follows: Duff & Standard Phelps & Poor's ------ -------- Corporate Credit Rating BBB- First Mortgage Bonds BBB BBB+ Preferred Stock BBB- BB+ On November 12, 1998, Catamount, a wholly owned non-utility subsidiary of the Company, replaced its $8.0 million credit facility with a $25.0 million revolving credit facility expiring November 11, 2002 which provides for up to $25.0 million in revolving credit loans and letters of credit. 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. Financial obligations of the non-utility wholly owned subsidiaries are non-recourse to the Company. Hydro-Quebec Contract The Company is a party to a power contract with Hydro-Quebec through the Vermont Joint Owners (VJO), a consortium of Vermont utilities which includes the Company, Green Mountain Power Corporation (GMP), Citizen's Utilities, Rochester Electric Light & Power and Vermont Public Power Supply Authority representing municipalities and a cooperative in Vermont. Under these agreements, there are "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 March 31, 1999 the Company's VJO obligation is approximately 46% or $1.0 billion 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 $2.3 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 contract with Hydro-Quebec. This resulted in an interruption of a significant portion of scheduled contractual power 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 in the future. That review has prompted the VJO to initiate an arbitration proceeding, the end result of which may be the termination of the contract. By way of the arbitration, the VJO is also seeking to recover capacity payments made during the period of non-delivery. Diversification Catamount was formed for the purpose of investing in non-regulated power plant projects. Currently, Catamount, through its wholly owned subsidiaries, has interests in five operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; and Hopewell, Virginia. In addition, Catamount has interests in projects under construction in Thetford, England, and in Summersville, West Virginia, and under development in Fort Dunlop, England. Catamount's after-tax earnings were $.6 million and $.7 million for the first quarter 1999 and 1998, respectively. SmartEnergy was formed to engage in the sale of or rental of electric water heaters, energy efficient products and other related goods and services. Currently, SmartEnergy, through its subsidiaries, has signed an agreement to have its SmartDrive dairy vacuum pump control manufactured and deliverd to domestic and worldwide markets; administers a fixed for variable rate swap contract for the cost of electrical service with two customers located in the state of Virginia, and has entered into a Test Marketing and License Agreement with Sam's Club, Inc. for the purpose of test marketing certain home service solution products and services to Sam's Club members at four test market locations which is scheduled to begin by the end of May 1999. SmartEnergy incurred losses of $.1 million and $.4 million for the first quarter of 1999 and 1998, respectively. Rates and Regulation The Company recognizes that adequate and timely rate relief is necessary if the Company is to maintain its financial strength, particularly since Vermont regulatory rules do not allow for changes in purchased power and fuel costs to be passed on to consumers through automatic rate adjustment clauses. The Company's practice of reviewing costs periodically will continue and rate increases will be requested when warranted. Vermont: 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 overlapped the 6.6% rate increase request referenced below that is now stayed pending a review on the so-called preclusion issue by the Vermont Supreme Court (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 rate increase is temporary insofar as it is subject to adjustment upon future resolution of the Hydro-Quebec Contract issues presently before the VSC. The Company anticipates a ruling by the VSC on the Hydro-Quebec issues the end of 1999. The agreement incorporates a disallowance of approximately $7.4 million for the Company's purchased power costs under the Hydro-Quebec Contract while the VSC reviews the PSB denial of the Company's claim that the PSB is precluded from again trying the Company on certain Hydro-Quebec Contract issues. This $7.4 million disallowance was calculated using the same formula as contained in the rate order issued by the PSB in the GMP rate case on February 28, 1998. Upon approval of the agreement by the PSB, the Company, during the fourth quarter of 1998, recorded a loss of $7.4 million on a pre-tax basis for disallowed purchased power costs, representing the Company's estimated under recovery of power costs under the Hydro-Quebec Contract. If the Company receives an unfavorable ruling from the VSC, and the PSB issues a rate order adopting the methodology used to determine the temporary Hydro-Quebec disallowance for the duration of the Hydro-Quebec Contract, approximately $205.0 million of power costs to be incurred under that contract would not be recoverable in rates. This would result in an immediate charge to earnings of $205.0 million on a pre-tax basis once such outcome became probable. Such an outcome would jeopardize the ability of the Company to continue as a going concern. 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 winter-summer rate differential 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. The PSB decided to appoint an independent investigator to examine the Company's decision to buy power from Hydro-Quebec. The Company filed a motion with the PSB stating that the PSB already examined the Company's decision to buy power from Hydro-Quebec and, therefore, the PSB as well as other parties should be barred from reviewing its past decision on Hydro-Quebec. However, the Company does not object to the independent investigator or others looking at issues of management of the power supply since the Company's last rate case. During February 1998, the DPS filed testimony in opposition to the Company's 6.6% or $15.4 million retail rate increase request. As a result of its testimony, the DPS recommended that the PSB instead reduce the Company's current retail rates by 2.5% or $5.7 million. 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 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 would 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 demand side management (DSM) 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. New Hampshire: On November 26, 1997, Connecticut Valley filed a request with the NHPUC to increase the Fuel Adjustment Clause (FAC) and Purchased Power Cost Adjustment (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 overcollections 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 3 to the Consolidated Financial Statements for additional information. 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 New Hampshire Public Utilities Commission (NHPUC) issued an Order allowing Connecticut Valley to increase 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 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. See Electric Industry Restructuring-New Hampshire for additional information related to the Court Order. Proposed Formation of Holding Company In order to further prepare the Company 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 direct 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's information systems could be affected by the date change in Year 2000 because most software application and operational programs will not properly recognize calendar dates beginning in the Year 2000. If not corrected, many computer applications could fail or create erroneous results. In order to meet current and future business needs the Company retained outside consultants to make its customer service applications Year 2000 compliant. In addition, the Company utilized both internal and external resources to make other applications, including its desk top applications, Year 2000 ready. Inventory, assessment and remediation activities are 100% complete. The Company expects to achieve compliance with Year 2000 requirements for all of its financial and operating systems by the end of the second quarter of 1999. The Company's operations would be adversely affected if a date-related system failure occurred with one of its major power suppliers, such as Hydro-Quebec or Vermont Yankee, or Velco, the company responsible for transmission in Vermont. Velco indicates it will be compliant by July 1999. Other delivery systems outside the state could, in the event of a date-related system failure, cause additional power supply interruptions. The Company has requested written reports from its power supply vendors regarding each Company's status relative to Year 2000 compliance and based on responses to date, these power supply vendors have indicated that they are either currently compliant or expect to be compliant by the third quarter of 1999. The Company has also requested compliance information from other major vendors and suppliers. While this process is not yet complete, based upon responses to date, many of those major vendors and suppliers have indicated that they will be Year 2000 compliant in a timely manner. However, there can be no guarantee that third parties' noncompliance and their failure to remediate Year 2000 issues would not have a material adverse effect on the Company. Failure on the part of the Company to comply by December 31, 1999 could have a material adverse effect on the Company's results of operations and financial condition. Also, failures of the Company's principal power and transmission suppliers to remedy Year 2000 compliance issues, could have a material adverse effect on the Company should non-compliance result in interruptions of power supply and transmission. The Company is part of the Northeast grid contingency plan that would go into effect immediately which would provide electricity to its customers on a priority basis in the event of power outages. The Company also has contingency plans developed in the event of the failure of its transmission, generation, distribution, metering, telecommunications, information and public communications systems. The Company believes it will incur approximately $3.6 million of costs associated with making the necessary modifications to its centralized and non-centralized computer systems. As of March 31, 1999, approximately $3.2 million of those costs have been incurred. During the first quarter of 1998, the Company requested an Accounting Order from the PSB to defer these operating and maintenance costs. On August 31, 1998, the PSB issued an Accounting Order authorizing the Company to defer a portion of these costs and amortize them over a five-year period beginning January 1, 2000. Per PSB Order dated December 11, 1998, the Company is authorized to recover these costs through the regulatory process. ELECTRIC INDUSTRY RESTRUCTURING The electric utility industry is in a period of transition that may result in a shift away from ratemaking based on cost of service and return on equity to more market-based rates. 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 On December 31, 1996, the PSB issued a Report and Order (the Report) outlining a restructuring plan (the Plan), subject to legislative approval, for the Vermont electric utility industry. Due to uncertainty surrounding legislative schedules, the PSB, on April 18, 1997, issued an Order which suspended, pending further legislative action or future PSB Orders, certain filing deadlines for reports and plans to be completed in connection with the Plan. On April 3, 1997, Senate Bill 62 (S.62), an act relating to electric industry restructuring was passed by the Vermont Senate. Pursuant to S.62, electric utility customers would have been entitled to purchase electricity in a competitive market place and could have chosen their electricity supplier. Incumbent investor-owned electric utilities, including the Company, would have been required to separate their regulated distribution and transmission operations from the competitive generation and retail operations. S.62 provided for the recovery of a portion of investor-owned utility's "above market costs" which became stranded on account of the introduction of competition within their service area. When considering the recovery of such amounts, S.62 would have required the PSB to weigh the goal of sharing net prudently incurred, discretionary above-market costs "evenly" between utilities and customers against other goals including preserving the continuing financial integrity of the existing utility and respecting the just interests of investors. The Company believes that the unmodified provisions of S.62 would not have met the criteria for continuing application of Statement of Financial Accounting Standards (SFAS) No. 71. S.62 also created an incentive for the Company to take steps to close the Vermont Yankee Nuclear Power Station by conditioning the recovery of certain plant-related stranded costs on the decision of its owners to cease operations in 1998, unless the PSB agreed to allow the plant to run for up to two more refuelings to avoid power shortages or for other public interest reasons. To become law, S.62 would have had to be passed by the Vermont House of Representatives and signed by the Governor of the State of Vermont. Since the 1998 Legislative session concluded in April 1998 and S.62 was not enacted by the Vermont House of Representatives and subsequently signed into law by the Governor of Vermont, the bill did not become law and any efforts to pursue it in the future will require that it be re-enacted by the Vermont Senate and passed by the Vermont House of Representatives. Instead of considering S.62, the Vermont House of Representatives convened a special committee to study matters relating to the reform of Vermont's electric utility system in the summer of 1997. That committee issued recommendations in a report and legislation was proposed that would have provided for reform but not adopt the recommendations concerning customer choice and competition set forth in the PSB's Report and Order. Other legislation intended to advance a portion of the PSB Report and Order was also introduced. However, neither the House of Representatives nor Vermont Senate acted on these reforms which must be reintroduced in the next Vermont legislative biennium that began in January 1999, if they are to be considered. Therefore, at this time, it cannot be determined whether future restructuring legislation will be enacted in 1999 that would conform to the concepts developed by the Report, S.62 or the House Special Committee report. On July 22, 1998, Governor Dean issued an Executive Order establishing a Working Group on Vermont's Electricity Future (the Working Group) 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 can 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 Governor Dean to gather information on and evaluate the possible consequences of the current financial status of Vermont electric utilities. The Working Group was asked to complete its review and report back to Governor Dean and to legislative leaders by December 15, 1998. A report was issued by the Working Group on December 18, 1998. Key conclusions of its report are: 1. Vermont should restructure its electric industry by moving rapidly to retail choice whereby consumers would purchase power directly from competing power suppliers. 2. Bankruptcy of Vermont electric utilities should not be viewed as an appropriate means to reduce Vermont utilities' above market power supply costs. 3. 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. 4. The Vermont electric utilities should pursue auctions of their power generation assets and remaining power contracts. 5. 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 rates in the nation, electricity costs in Vermont have been among the lowest in the region. However, that advantage is eroding as other states in New England restructure their electric utility industries. Therefore, the Working Group recommends that it is in the interest of Vermont ratepayers to have the benefit of a restructured electric utility industry as soon as possible. The Company has signed a confidentiality and cooperation agreement with GMP and Citizens Utilities to permit an exchange of information to evaluate the possibility of consolidating the Vermont operations of the three utilities. In addition, the Washington Electric Cooperative (WEC) has recommended that consideration be given to its acquiring Vermont's investor owned utilities and converting them to a cooperative ownership structure. The Company also signed a confidentiality and cooperation agreement with WEC. The Company supports the Working Group recommendations and believes that they can be implemented without legislative change. During the first quarter of 1999 the Company and GMP filed with the PSB a plan that would bring electric industry competition to Vermont, stabilize power costs and streamline energy-efficiency programs as follows: 1. The Company and GMP would voluntary give up the exclusive right to serve their present electricity customers, allowing competitive electricity sales to about 70% of the electric customers in the state in the context of a global settlement. 2. The Company and GMP would refinance and renegotiate Hydro-Quebec and Small Power Producers' power contracts to bring down the costs. 3. The Company and GMP would evaluate wholly owned and jointly owned generating sources, including Vermont Yankee, and decide which ones were most appropriate for sale. Efforts to sell Vermont Yankee are already under way. On February 25, 1999, the Board of Directors of Vermont Yankee granted an exclusive right to AmerGen Energy Co. to conduct due diligence and negotiate a possible agreement to purchase the assets of Vermont Yankee. 4. The state of Vermont would create an efficiency utility to streamline energy-efficiency services for electric customers. As further discussed below, the Company and GMP have entered into a Memorandum of Understanding with the DPS for the creation of an energy efficiency utility. 5. In the future, a petition may be filed with regulators that could lead to the consolidation of some of Vermont's electric distribution companies into a new company. The Company believes that this plan provides Vermont with the best opportunity to stabilize customer rates, open markets to competition and return the electric industry to sound footing. The Company expects to formally submit its proposal to the PSB during the fall of 1999. On August 27, 1998, the PSB hosted a workshop entitled, "Electricity Futures: Reforming Vermont's Power Supply", which was organized to facilitate power supply reform. Participants heard reports on successful power supply reforms in other states, followed by a discussion intended to identify opportunities and next steps, and to elicit proposals for reformulating Vermont's electric power supply. This workshop generated a great deal of interest with over 140 attendees, representing Vermont retail electric utilities, both large and small electricity consumers, public officials and interest groups, and several current and aspiring energy suppliers. As a follow up to the workshop, 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 explained that it intends that this proceeding will define one or more acceptable courses for reform, and will create the framework to enable Vermont utilities and other interested parties to pursue them and to present them for regulatory approval in an open, public process. 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 as well as the WEC acquisition proposal. As of this time, the PSB has yet to act on any proposal or recommendation made concerning the disposition of the matters in Docket No. 6140. 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 intends to issue final, binding and appealable orders concerning matters related to the reform and restructuring of Vermont's electric utility industry. Initially, the PSB noticed 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 will include 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. The PSB explains that this proceeding will provide utilities the maximum structural guidance on the terms and conditions it will consider in a voluntary restructuring proposal. As of this time, formal proceedings in Docket No. 6140-A are only at a preliminary status, however the PSB indicates that it will proceed quickly to conclude this proceeding. Consistent with the Company's restructuring plan, on April 30, 1999 the Company and GMP entered into a Memorandum of Understanding (the MOU) with the DPS for the creation of an energy efficiency utility (EEU) to provide system-wide DSM services. Subsequently, other Vermont utilities including Citizens Utilities and the Vermont Electric Coop, as well as consumer interest groups, have endorsed the proposal. The MOU was filed with the PSB on April 30, 1999 for approval in Docket No. 5980 which was opened by the PSB to investigate the DPS's proposed Statewide Energy Efficiency Plan. If approved by the PSB, the MOU would resolve all issues now outstanding in Docket No. 5980 including, the governance structure for the EEU, the design of the EEU programs and services, and the EEU budgets. The MOU also resolves all claims based on actions or failures to act prior to January 1, 2000 that the Company failed to satisfy its DSM obligations to customers under Vermont law and regulation. The PSB is currently considering the approval of the MOU which is expected by summer of 1999. If approved by the PSB, the new energy efficiency delivery system would be in place beginning in year 2000 and would replace services now provided to customers by the Company. New Hampshire 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 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 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 overcollections 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 Federal District Court (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 April 3, 1998, the Court held a hearing on the Companies' motion for a Temporary Restraining Order (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 have been allowed to intervene in these proceedings, including the Company and Connecticut Valley. The plaintiffs-intervenors 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 (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 cancelled because of the Court's June 5, 1998 Order, discussed below. On June 5, 1998, the Court issued an Order which denied 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 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 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 which mandated Connecticut Valley to provide a refund to its retail customers was illegal and the imposition of the refund went beyond the authority of the NHPUC. 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 remaining stay of restructuring activities and indicated 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 Company expects the hearings on the permanent injunction will take place later this year. 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. No order has been issued on this matter. 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 increase 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, which are included in the estimated total losses of $4.3 million discussed below. As a result of legal and regulatory actions discussed above, Connecticut Valley no longer qualifies for the application of SFAS No. 71, and wrote-off all its regulatory assets associated with its New Hampshire retail business estimated at approximately $1.3 million on a pre-tax basis. In addition, Connecticut Valley recorded estimated total losses of $4.3 million pre-tax for disallowed power costs of $1.6 million and 1998 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 forums. The pre-tax losses described above resulted in Connecticut Valley violating applicable covenants, which if not waived or renegotiated, would allow 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 June 25, 1997, the Company filed with the FERC a notice of termination of its power supply contract with Connecticut Valley, conditional upon the Company's request to impose a surcharge on the Company's transmission tariff to recover the stranded costs that would result from the termination of its contract with Connecticut Valley. The amount requested was $44.9 million plus interest at the prime rate to be recovered over a ten-year period. In its Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected the Company's proposed stranded cost surcharge mechanism but indicated that it would consider an exit fee mechanism for collecting stranded costs. The FERC also rejected the Company's arguments concerning the applicability of stated FERC policies regarding retail stranded costs, multi-state regulatory gaps and the implications of state restructuring initiatives. The Company filed a motion seeking rehearing of the FERC's December 18, 1997 Order which was denied. Thereafter, the Company appealed the FERC's decision to the Court of Appeals for the District of Columbia circuit. In addition, and in accordance with the December 18, 1997 FERC Order, on January 12, 1998 the Company filed a request with the FERC for an exit fee mechanism to collect $44.9 million in a lump sum, or in installments with interest at the prime rate over a ten-year period, to cover the stranded costs resulting from the cancellation of Connecticut Valley's power contract with the Company. On March 11, 1998, the FERC issued an order accepting for filing the Company's request for an exit fee effective March 14, 1998, and set hearings to determine: whether Connecticut Valley will become an unbundled transmission customer of the Company, the Company's expectation as to the period of time it would serve Connecticut Valley, and the allowable amount of the exit fee. The FERC also rejected the Company's June 25, 1997 notice of termination indicating that the notice can be resubmitted when the power contract is proposed to be terminated. On April 28, 1998, the Company filed its case-in-chief before the FERC updating the amount of the exit fee to $54.9 million in a lump sum, describing 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. Had termination taken effect on January 1, 1998 this expectation period would have equaled nineteen years. On August 4 and 5, 1998 Phase 1 hearings were held at the FERC on the issue of whether Connecticut Valley will become an unbundled transmission customer of the Company. Subsequent to those hearings, the parties agreed to go on to hearings on the Phase 2 issues (addressing the allowable amount of the exit fee) without a preliminary determination from the Administrative Law Judge or the FERC on the Phase 1 issues. The Company submitted supplemental testimony on Phase 2 issues on December 3, 1998 and the hearings were completed on May 10, 1999. From April 27 through May 10, 1999, nine days of hearings were held at the FERC on the Phase II issues of (1) whether the Company has overcome the rebuttable presumption that its expectation to provide wholesale power service to Connecticut Valley extends beyond the one year termination notice provision contained in its otherwise automatically renewing FERC regulated rate schedule and (2) if rebutted, the amount of Connecticut Valley's stranded cost obligation to be paid the Company as an exit fee. During the course of the hearings, the Company reached a partial stipulation with the parties that resulted in revision of its requested exit fee to approximately $48.0 million had termination taken place on January 1, 1999. If the Company is unable to obtain an order authorizing the full recovery amount of the exit fee, or other appropriate mechanism, the Company would be required to recognize a loss under this contract totaling approximately $60.0 million on a pre-tax basis. Furthermore, the Company would be required to write-off approximately $4.0 million in regulatory assets associated with its wholesale business on a pre-tax basis. Conversely, even if the Company obtains a FERC order authorizing the updated requested exit fee, Connecticut Valley would be required to recognize a loss under this contract of approximately $48.0 million on a pre-tax basis unless Connecticut Valley has obtained an order by the NHPUC or other appropriate body directing the recovery of those costs in Connecticut Valley's retail rates. Either of these reasonably possible outcomes could occur during calendar year 1999. The Company 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, cash flows, and ability to obtain capital at competitive rates. 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 and 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 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 Report 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 and attract new customers or the margins that will be realized on retail sales of electricity. Historically, electric utility rates have been based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. 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 included in its 1998 Annual Report on Form 10-K, 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 $63.7 million on a pre-tax basis as of March 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, 1998, 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. 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 two pending rate cases 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. CENTRAL VERMONT PUBLIC SERVICE CORPORATION PART II - OTHER INFORMATION Item 1. 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 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. Except as otherwise described under Management's Discussion and Analysis of Financial Condition and Results of Operations, Item 2, 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. Items 2 and 3. None. Item 4. Submission of Matters to a Vote of Security Holders. (a) The Registrant held its Annual Meeting of Stockholders on May 4, 1999. (b) Director elected whose term will expire in year 2001: Votes FOR Votes WITHHELD Janice L. Scites 9,170,580 236,696 Directors elected whose terms will expire in year 2002: Votes FOR Votes WITHHELD Rhonda L. Brooks 9,185,903 221,373 Patrick J. Martin 9,194,841 212,435 Robert H. Young 9,187,899 219,377 Other Directors whose terms will expire in 2000: Frederic H. Bertrand Robert L. Barnett Robert G. Clarke Mary Alice McKenzie Item 5. Other Information. In May 1999, the City Council of the City of Claremont New Hampshire 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 will require that the City 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 without the municipality as the public interest may require. The Company would thereafter have sixty days to reply to the City's inquiry. If there is no agreement between the Company and the City, Claremont may proceed to condemn the Company's facilities with proceedings before the New Hampshire Public Utilities Commission as provided for in Chapter 38 and the FERC as provided for in its Rule 35.26 (18CFR Chapter 1). At this time, no date has been selected for the necessary confirming vote by qualified Claremont voters. The Company intends to vigorously pursue its rights. Item 6. Exhibits and Reports on Form 8-K. (a) List of Exhibits 10. Material Contracts A 10.89 Management Incentive Plan for Executive Officers dated January 1, 1999 A - compensation related plan, contract or arrangement 27. Financial Data Schedule (b) Item 5. Other Events, dated February 2, 1999 re: Standard & Poor's Corporation lowering the Company's corporate credit rating. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. CENTRAL VERMONT PUBLIC SERVICE CORPORATION (Registrant) By Francis J. Boyle Francis J. Boyle, Senior Vice President, Principal Financial Officer and Treasurer By James M. Pennington James M. Pennington, Vice President, Controller and Principal Accounting Officer Dated May 13, 1999 EX-27 2 EXHIBIT 27 - FINANCIAL DATA SCHEDULE
UT This Financial Data Schedule contains summary financial information extracted from the Consolidated Financial Statements included herein and is qualified in its entirety by reference to such financial statements (dollars in thousands, except per share amounts). 1,000 3-MOS DEC-31-1999 MAR-31-1999 PER-BOOK 318046 66383 86418 68792 0 539639 66481 45324 80013 191453 17000 8054 90071 0 0 0 6773 1000 15871 1094 208323 539639 98642 7557 77230 84787 13855 1464 15319 2589 12730 465 12265 0 1573 28436 1.07 1.07
EX-10 3 EXHIBIT 10.89 FOR 3-31-99 FORM 10-Q EXHIBIT A 10.89 - - - - - - - - - - - - - ----------------------- CENTRAL VERMONT PUBLIC SERVICE CORPORATION MANAGEMENT INCENTIVE PLAN Adopted As Of January 1, 1999 I. PURPOSE The Company's executive officers participate in the Company's annual Management Incentive Plan (the "MIP"). The purpose of the MIP is to focus the efforts of the executive team on the achievement of challenging and demanding corporate objectives. When corporate performance attains the specified annual performance objectives, an award is granted. This incentive plan, in conjunction with competitive salaries and long-term incentives, provides a level of compensation which rewards the skills and efforts of the executives commensurate with market comparisons. II. ADMINISTRATION The MIP will be administered by the Compensation Committee of the Board of Directors (the "Committee"). All Committee actions will be subject to review and approval by the full Board of Directors (the "Board"). At the beginning of each year ("Plan Year"), the Committee will submit to the Board its recommendations for that Plan Year as to (i) the MIP's Corporate Performance Goals, and (ii) the eligible participants. After the end of each Plan Year, the Committee will report to the Board with respect to achievement of the approved Corporate Performance Goals and individual performance measures for that Plan Year, and will submit to the Board its recommendations as to the appropriate award payment levels for each eligible participant. Recommendations of the Committee, with such modifications as may be made by the Board, will be binding on all participants in the MIP. III. THE PLAN Performance measures must be met in the following areas to receive an award. Each measure is equally weighted, representing one-third of the potential payout. Consolidated earnings per share. Consolidated earnings per share measures the overall financial performance of the company. Customer satisfaction. Measures (1) the overall degree of satisfaction by all customers and (2) the level of satisfaction with specific service by customers who have had a recent service interaction. The measurement is conducted by an external firm. Individual performance. Performance is measured vs. objectives for the year for each Executive Officer based on advice and recommendation from the Chief Executive Officer. The Committee and Board evaluate the Chief Executive Officer's performance vs. his objectives. The total award if the maximum payout on all three of these measures were to be met, would represent 35% of base salary for the Chief Executive Officer; 25% of base salary for the Senior Vice Presidents and Vice President and General Manager for Business Development; 20% for other Vice Presidents and Assistant Vice Presidents. If the targeted level of EPS is exceeded, the total award is increased by 10%. IV. AWARDS Any annual incentive award will consist of cash (50%) and Central Vermont Public Service Corporation stock (50%) which will have a three year vesting restriction. The restricted stock portion has an additional 25% premium. Applicable dividends will be paid on awarded restricted stock prior to vesting. V. AMENDMENTS The Board reserves the right to amend, modify or terminate the MIP at any time. -----END PRIVACY-ENHANCED MESSAGE-----