-----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, UpjzczYEIuqy4U8UrAvymZ9SxCIIsyOb2lBDbpxp3UteaE9AG9rzXCWXfgBjvNOm wQ5cE6nvW7Wb478yQgs2fw== 0000018808-98-000034.txt : 19980528 0000018808-98-000034.hdr.sgml : 19980528 ACCESSION NUMBER: 0000018808-98-000034 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19980331 FILED AS OF DATE: 19980515 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CENTRAL VERMONT PUBLIC SERVICE CORP CENTRAL INDEX KEY: 0000018808 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 030111290 STATE OF INCORPORATION: VT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-08222 FILM NUMBER: 98622674 BUSINESS ADDRESS: STREET 1: 77 GROVE ST CITY: RUTLAND STATE: VT ZIP: 05701 BUSINESS PHONE: 8027732711 10-Q 1 FORM 10-Q PERIOD ENDING 3/31/98 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, 1998 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, 1998 there were outstanding 11,425,651 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, 1998 and 1997 3 Consolidated Balance Sheet as of March 31, 1998 and December 31, 1997 4 Consolidated Statement of Cash Flows for the three months ended March 31, 1998 and 1997 5 Notes to Consolidated Financial Statements 6-11 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 12-24 PART II. OTHER INFORMATION 25-26 SIGNATURE 27 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 1998 1997 ---- ---- Operating Revenues $83,958 $88,494 ------- ------- Operating Expenses Operation Purchased power 39,706 40,996 Production and transmission 5,588 5,677 Other operation 11,434 9,985 Maintenance 3,852 3,041 Depreciation 4,227 4,460 Other taxes, principally property taxes 3,040 2,988 Taxes on income 5,432 7,207 ------- ------- Total operating expenses 73,279 74,354 ------- ------- Operating Income 10,679 14,140 ------- ------- Other Income and Deductions Equity in earnings of affiliates 732 885 Allowance for equity funds during construction 17 20 Other income, net 578 2,733 Provision for income taxes 10 (882) ------- ------- Total other income and deductions, net 1,337 2,756 ------- ------- Total Operating and Other Income 12,016 16,896 ------- ------- Interest Expense Interest on long-term debt 2,531 2,511 Other interest 103 74 Allowance for borrowed funds during construction (9) (8) ------- ------- Total interest expense, net 2,625 2,577 ------- ------- Net Income Before Extraordinary Credit 9,391 14,319 Extraordinary Credit Net of Taxes 873 - ------- ------- Net Income 10,264 14,319 Retained Earnings at Beginning of Period 75,841 74,137 ------- ------- 86,105 88,456 Cash Dividends Declared Preferred stock 486 507 Common stock 6 2,534 ------- ------- Total dividends declared 492 3,041 ------- ------- Retained Earnings at End of Period $85,613 $85,415 ======= ======= Earnings Available For Common Stock $ 9,778 $13,812 Average Shares of Common Stock Outstanding 11,423,951 11,519,748 Basic and Diluted Share of Common Stock: Earnings before extraordinary credit $.78 $1.20 Extraordinary credit .08 - ---- ----- Earnings Per Basic and Diluted Share of Common Stock $.86 $1.20 ==== ===== 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 1998 1997 ---- ---- Assets Utility Plant, at original cost $461,764 $461,482 Less accumulated depreciation 155,354 151,250 -------- -------- 306,410 310,232 Construction work in progress 12,818 10,450 Nuclear fuel, net 947 964 -------- -------- Net utility plant 320,175 321,646 -------- -------- Investments and Other Assets Investments in affiliates, at equity 26,562 26,495 Non-utility investments 34,330 33,736 Non-utility property, less accumulated depreciation 2,848 2,894 -------- -------- Total investments and other assets 63,740 63,125 -------- -------- Current Assets Cash and cash equivalents 25,949 16,506 Special deposits 432 404 Accounts receivable, less allowance for uncollectible accounts ($1,950 in 1998 and $1,946 in 1997) 25,832 23,166 Unbilled revenues 12,359 18,951 Materials and supplies, at average cost 3,772 3,779 Prepayments 2,000 1,464 Other current assets 5,059 4,970 -------- -------- Total current assets 75,403 69,240 -------- -------- Regulatory Assets 72,848 73,209 -------- -------- Other Deferred Charges 5,133 4,720 -------- -------- Total Assets $537,299 $531,940 ======== ======== 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 45,302 45,295 Treasury stock (360,197 shares and 362,447 shares, respectively, at cost) (4,699) (4,728) Retained earnings 85,613 75,841 -------- -------- Total common stock equity 196,931 187,123 Preferred and preference stock 8,054 8,054 Preferred stock with sinking fund requirements 18,000 19,000 Long-term debt 108,844 93,099 Long-term lease arrangements 16,952 17,223 -------- -------- Total capitalization 348,781 324,499 -------- -------- Current Liabilities Short-term debt 250 12,650 Current portion of long-term debt and preferred stock 21,521 24,271 Accounts payable 5,349 4,609 Accounts payable - affiliates 14,622 12,441 Accrued income taxes 4,461 6,631 Dividends declared 486 2,513 Nuclear decommissioning costs 6,010 6,010 Other current liabilities 18,927 21,646 -------- -------- Total current liabilities 71,626 90,771 -------- -------- Deferred Credits Deferred income taxes 56,100 53,996 Deferred investment tax credits 7,125 7,222 Nuclear decommissioning costs 27,381 28,947 Other deferred credits 26,286 26,505 -------- -------- Total deferred credits 116,892 116,670 -------- -------- Total Capitalization and Liabilities $537,299 $531,940 ======== ======== 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 1998 1997 ---- ---- Cash Flows Provided (Used) By Operating Activities Net income $10,264 $14,319 Adjustments to reconcile net income to net cash provided by operating activities Equity in earnings of affiliates (732) (885) Dividends received from affiliates 618 893 Equity in earnings of non-utility investments (1,659) (1,281) Distribution of earnings from non-utility investments 1,184 614 Extraordinary credit (873) - Depreciation 4,227 4,460 Deferred income taxes and investment tax credits 1,723 333 Allowance for equity funds during construction (17) (20) Net deferral and amortization of nuclear refueling replacement energy and maintenance costs (1,345) 1,409 Amortization of conservation and load management costs 1,755 1,755 Gain on sale of property - (2,095) Decrease in accounts receivable and unbilled revenues 4,482 329 Increase (decrease) in accounts payable 3,364 (802) Increase (decrease) in accrued income taxes (2,171) 6,714 Change in other working capital items (3,531) 3,141 Other, net (933) (727) ------- ------- Net cash provided by operating activities 16,356 28,157 ------- ------- Investing Activities Construction and plant expenditures (3,242) (3,399) Deferred conservation & load management expenditures (568) (575) Return of capital 47 47 Proceeds from sale of property - 2,210 Non-utility investments (100) (776) Other investments, net (156) (120) ------- ------- Net cash used for investing activities (4,019) (2,613) ------- ------- Financing Activities Short-term debt, net (400) (5,750) Long-term debt, net (5) (5) Common and preferred dividends paid (2,518) (3,041) Sale of treasury stock 29 - ------- ------- Net cash used for financing activities (2,894) (8,796) ------- ------- Net Increase in Cash and Cash Equivalents 9,443 16,748 Cash and Cash Equivalents at Beginning of Period 16,506 6,365 ------- ------- Cash and Cash Equivalents at End of Period $25,949 $23,113 ======= ======= Supplemental Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) $ 586 $ 303 Income taxes (net of refunds) $ 5,851 $ 1,251 The accompanying notes are an integral part of these consolidated financial statements. CENTRAL VERMONT PUBLIC SERVICE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS March 31, 1998 Note 1 - Accounting Policies The Company's significant accounting policies are described in Note 1 of Notes to Consolidated Financial Statements included in its 1997 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. See Note 3 below for detail in regard to a Court Order issued on April 9, 1998 by the United States Court for the District of New Hampshire, sitting in Rhode Island (Court) which again qualifies Connecticut Valley Electric Company Inc. (Connecticut Valley), the Company's New Hampshire subsidiary, to prepare its financial statements in accordance with Statement of Financial Accounting Standards (SFAS) No. 71. RECLASSIFICATION Certain reclassifications have been made to prior year Consolidated Financial Statements to conform with the 1998 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. For related information see Part II Item 1, Legal Proceedings below. CLEVELAND AVENUE PROPERTY One such site is the Company's Cleveland Avenue property located in the City of Rutland, Vermont, a site where one of its predecessors operated a coal-gasification facility and later the Company sited various operations functions. Due to the presence of coal tar deposits and Polychlorinated Biphenyl (PCB) contamination and uncertainties as to potential off-site migration of those contaminants, the Company conducted studies in the late 1980's and early 1990's to determine the magnitude and extent of the contamination. 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 million. This was charged to expense in the fourth quarter of 1992. Site investigation continued over the next several years. In January of 1995, the Company was formally contacted by the EPA asking for written consent to conduct a site evaluation of the Cleveland Avenue property. That evaluation has been completed. The Company does not believe the EPA's evaluation changes its potential liability so long as the State remains satisfied that reasonable progress continues to be made in remediating the site and retains oversight of the process. In 1995, as part of that process, the Company's consultant completed its risk assessment report and submitted it to the State of Vermont for review. The State generally agreed with that assessment but expressed a number of concerns and directed the Company to collect some additional data. The Company has addressed almost all of the concerns expressed by the State and continues to work with the State in a joint effort to develop a mutually acceptable solution. The Company selected a consulting/engineering firm to collect the additional data requested by the State and develop and implement a remediation plan for the site. That firm has begun work at the site. It has collected the additional data requested by the State and will use all the data gathered to date to formulate a comprehensive remediation plan. The additional data gathered to date has not caused the Company to alter its original estimate of the likely cost of remediating the site. PCB, INC. AND OSAGE METALS In August 1995, the Company received an Information Request from the EPA pursuant to a Superfund investigation of three related sites, located in Kansas and in Missouri (the Sites). During the mid-1980's, these Sites received materials containing PCBs from hundreds of sources, including the Company. According to the EPA, more than 1,200 parties have been identified as Potential Responsible Parties (PRPs). The Company has complied with the information request and will monitor EPA activities at the Sites. In December 1996, the Company received an invitation to join a PRP steering committee. 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 .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. PARKER LANDFILL AND THE TRAFTON-HOISINGTON LANDFILL The Company also faces potential liability arising from the alleged disposal of hazardous materials at these two former municipal landfills. There have been no further developments involving the Company at these two sites. The Company's investigations at the time it was originally contacted indicated that it contributed little if any hazardous substances to the sites. The Company has not been contacted by the EPA, the State or any of the PRPs since 1994. Therefore, the Company believes that the likelihood that these sites will cause the Company to accrue significant liability has significantly diminished. At this time, the Company does not believe the landfill sites represent the potential for a material adverse effect on its financial condition or results of operations but it will continue to monitor activities at the sites. The Company is not subject to any pending or threatened litigation with respect to any other sites that have the potential for causing the Company to incur material remediation expenses, nor has the EPA or other federal or state agency sought contribution from the Company for the study or remediation of any such sites. In 1996, the Company filed a lawsuit in federal court against a number of insurance companies. In its complaint, the Company alleges that general liability policies issued by the insurers provide coverage for all expenses incurred or to be incurred by the Company in conjunction with, among others, the Cleveland Avenue Property. Settlements have been reached with all but one defendant, with whom the Company has reached a settlement in principle. Due to the uncertainties associated with the outcome of this lawsuit related to the remaining defendant and the actual clean-up costs, the proceeds have been applied to the environmental reserve. 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 general rate increase on September 22, 1997 to become effective June 6, 1998 to offset increasing cost of providing service. Approximately $14.3 million or 92.9% of the rate increase request is 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 have 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 Vermont Public Service Board's (PSB) 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 recently severely penalized another VJO member, Green Mountain Power Corporation, 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 current rate case. As such, the Company and other parties have 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. Because the appeal and associated stay of the rate case will significantly delay the date that the Company could increase rates, the Company's revenues and earnings' prospects for 1998 will be adversely affected. In an effort to mitigate the result, the Company expects to file with the PSB a request for additional rate relief. The nature, magnitude and timing of such a request has not yet been determined. New Hampshire: On November 26, 1997, Connecticut Valley filed a request with the New Hampshire Public Utilities Commission (NHPUC) to increase the Fuel Adjustment Clause (FAC), Purchased Power Cost Adjustment (PPCA) and short-term energy purchase rates effective on or after January 1, 1998. The requested increase in rates results from higher forecast energy and capacity charges on power Connecticut Valley purchases from the Company plus removal of credit effective during 1997 to refund overcollections from 1996. In an order dated December 31, 1997, the NHPUC 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 (Companies) filed with the Court for a temporary restraining order to maintain the status quo ante by staying the NHPUC Order of December 31, 1997 and preventing the NHPUC from taking any action that (i) compromises cost-based rate making for Connecticut Valley; (ii) interferes with 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 March 20, 1998, the NHPUC issued an order which affirms, clarifies and modifies 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 addresses all outstanding motions for rehearings or clarification relative to the policies or legal positions articulated in the Final Plan and removes 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 issued from the bench, which was continued 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 has 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. Also, on April 3, 1998, the Court indicated its 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 have 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. Subsequently, the NHPUC filed a motion to dismiss PSNH's pending complaint on which the November hearing is scheduled. The Company has sought leave of Court to file a brief in opposition to this motion. As a result of these Court orders, Connecticut Valley's 1997 charges under SFAS No. 5 and SFAS No. 71, described below in Management's Discussion and Analysis of Financial Condition and Results of Operations - Electric Industry Restructuring, 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 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 will exercise all of its remedies from and after May 5, 1998 in the event that the violations are not cured. After reversing the 1997 write-offs described above, Connecticut Valley will be in compliance with the financial covenants associated with its $3.75 million loan with the Bank. As a result, Connecticut Valley has 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 has been scheduled for June 11, 1998. 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 has filed a motion seeking rehearing of the FERC's December 18, 1997 Order. 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. 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 SFAS No. 5 totaling approximately $75.0 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 under SFAS No. 71 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 SFAS No. 5 of approximately $54.9 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 1998. The Company has initiated and will continue to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC. The Company cannot predict the ultimate outcome of this matter. However, an adverse resolution could have a material adverse effect on the Company's results of operations, cash flows, and ability to obtain capital at competitive rates. Note 4 - 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 1998 1997 ---- ---- Operating revenues $51,170 $40,421 Operating income $ 3,760 $ 3,711 Net income $ 1,702 $ 1,775 Company's equity in net income $510 $556 CENTRAL VERMONT PUBLIC SERVICE CORPORATION Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS March 31, 1998 Earnings Overview Earnings available for common stock and earnings per share of common stock for the quarter ended March 31, 1998 were $9.8 million and $.86 compared to $13.8 million and $1.20 for the corresponding period last year. Earnings available for common stock and earnings per share of common stock include the positive impact of the reversal of a fourth quarter 1997 charge of $3.6 million and $.31, respectively. This 1997 charge represented the estimated loss on a FERC-approved power contract with the Company during 1998 at Connecticut Valley. The reversal of this 1997 charge results from a federal court order issued on April 9, 1998. (See Electric Industry Restructuring - New Hampshire below and Note 1 in Notes to Consolidated Financial Statements for more information.) The court order directed the NHPUC to allow Connecticut Valley to recover through retail rates all costs for power it purchases from the Company pursuant to FERC-authorized rate schedules. In addition, because the court order restores Connecticut Valley to cost-based rate-making, net income and earnings per share of common stock for the first quarter of 1998 were increased by an after-tax extraordinary credit of $.9 million and $.08, respectively. This reverses a charge of a like amount taken in the fourth quarter of 1997. Other factors affecting results for 1998 are described in Results of Operations below. Earnings for the first quarter of 1997 reflect a net of tax gain from sale of property of approximately $1.3 million, or $.12 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, 1998 and 1997 (and the related percentage changes from 1997) is set forth below:
Three Months Ended March 31 ------------------------------------------------ Percentage Percentage MWH Increase Revenues (000's) Increase 1998 1997 (Decrease) 1998 1997 (Decrease) ------- ------- ---------- ------- ------- ---------- Residential 264,461 275,287 (3.9) $35,177 $35,803 (1.7) Commercial 228,432 230,075 (.7) 27,462 30,400 (9.7) Industrial 109,888 115,644 (5.0) 10,095 10,654 (5.2) Other retail 1,802 1,763 2.2 483 471 2.5 ------- ------- ------- ------- Total retail sales 604,583 622,769 (2.9) 73,217 77,328 (5.3) ------- ------- ------- ------- Resale sales: Firm 674 265 154.3 19 11 72.7 Entitlement 85,012 110,863 (23.3) 4,984 4,955 .6 Other 170,089 195,375 (12.9) 4,604 4,807 (4.2) ------- ------- ------- ------- Total resale sales 255,775 306,503 (16.6) 9,607 9,773 (1.7) ------- ------- ------- ------- Other revenues - - - 1,134 1,393 (18.6) ------- ------- ------- ------- Total sales 860,358 929,272 (7.4) $83,958 $88,494 (5.1) ======= ======= ======= =======
Retail MWH sales for the first quarter of 1998 decreased 2.9% compared to the first quarter of 1997 reflecting moderate temperature not typical of a Vermont winter. Retail revenues decreased $4.1 million , or 5.3% compared to last year. This negative variance is attributable to a $2.1 million impact of lower MWH sales in the first quarter of 1998 as compared to the first quarter of 1997 and $2.0 million resulting from a modified rate design reflected in bills rendered since April 1, 1997 which reduced the price charged per MWH during the first quarter of 1998 compared to the 1997 quarter. The modified rate design, which is revenue neutral on an annual basis, decreases prices charged during the winter months of December through March and increases prices during the remaining months of the year. For the first quarter of 1998, entitlement MWH sales decreased 23.3% while related revenues were about the same compared to the same period last year. The 25,286 MWH decrease ($.2 million) in other resale sales resulted principally from decreased sales to NEPOOL and to other utilities in New England partially offset by an increase in system capacity sales. Due to lower revenues associated with pole attachment rentals, other revenues decreased $.3 million for the first quarter of 1998 compared to the same period last year. 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, 1998 and 1997 are as follows (dollars in thousands):
1998 1997 Units Amount Units Amount ----- ------ ----- ------ Purchased and produced: Capacity (MW) 569 $20,441 524 $21,288 Energy (MWH) 836,276 19,265 926,064 19,708 ------- ------- Total purchased power costs 39,706 40,996 Production fuel (MWH) 75,075 515 60,726 266 ------- ------- Total purchased power and production fuel costs 40,221 41,262 Entitlement and other resale sales (MWH) 255,101 9,588 306,238 9,761 ------- ------- Net purchased power and production fuel costs $30,633 $31,501 ======= =======
Net purchased power and production fuel costs decreased $.9 million, or 2.8% for the first quarter of 1998 compared to the first quarter of 1997. However, absent the benefit of the 1997 Connecticut Valley reversal discussed above, net purchased power and production fuel costs increased $4.6 million, or 14.7% for 1998 compared to the same period last year primarily as the result of higher costs under the Hydro-Quebec power contract. Pursuant to a Vermont Public Service Board (PSB) Accounting Order, first quarter 1997 energy costs were reduced by approximately $2.9 million related to a Hydro-Quebec agreement. 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 1154 MW nuclear unit. 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) has been out of service since March 30, 1996, due to numerous technical and non-technical problems and is on the Nuclear Regulatory Commission's (NRC) watch list. The Company's share of the total incremental operating and maintenance costs for Unit #3 were about $1.0 million for 1997 and are expected to be about $.3 million for 1998. Incremental power costs for 1998 are estimated to be about $130,000 per month. All comprehensive plans to restart Unit #3 are implemented and Unit #3 was ready for NRC's operational safety inspection on April 13, 1998. The Company anticipates Unit #3 to resume operations during the third 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. 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. 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. Vermont Yankee The Vermont Yankee Nuclear Power Plant, which provides approximately one-third of the Company's power supply, began a refueling outage on March 21, 1998 and is expected to return to service during May 1998. The Company expects to defer approximately $1.8 million and $5.9 million for replacement energy and maintenance costs, respectively. These deferrals will be amortized to expense over eighteen months which is the expected in service period before Vermont Yankee's next scheduled refueling outage. The Design Basis Documentation project (Project) initiated by Vermont Yankee during 1996 is expected to be completed by the end of year 2000. The Company's 35% share of the total cost for this Project is expected to be about $5.9 million. Such costs will be deferred by Vermont Yankee and amortized over the remaining license life of the plant. 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 approximately $16.6 million, $12.4 million and $4.4 million, respectively. These amounts are subject to ongoing review and revisions and are reflected in the accompanying balance sheet both as regulatory assets and deferred power contract obligations (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. Other Operation Other operating expenses increased $1.4 million for the first quarter of 1998 compared to the first quarter of 1997 principally due to increased consulting and regulatory commission expenses. Maintenance The increase in maintenance expenses of $.8 million for the first quarter of 1998 compared to the same period in 1997 is attributable to a severe ice storm in January 1998. Income Taxes Federal and state income taxes fluctuate with the level of pre-tax earnings. The decrease in total income tax expense for the first quarter of 1998 results primarily from a decrease in pre-tax earnings for the period. Other Income and Deductions Due to lower earnings from the Company's nuclear generating and transmission affiliates, equity in earnings of affiliates decreased $.2 million for the first quarter of 1998 compared to the same period in 1997. The decrease in other income, net for the 1998 first quarter results primarily from a gain of $1.3 million from a non-recurring asset sale in February 1997. Extraordinary Credit The 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 discussed above. Dividends Declared The decrease in common dividends declared results from an early declaration made in December 1997 for the quarterly dividend paid on February 13, 1998. LIQUIDITY AND CAPITAL RESOURCES Construction - The Company's liquidity is primarily affected by the level of cash generated from operations and the funding requirements of its ongoing construction and C&LM programs. Net cash provided by operating activities generated $16.3 million and $28.2 million for the three months ended March 31, 1998 and 1997, respectively. The Company ended the first three months of 1998 with cash and cash equivalents of $25.9 million, an increase of $9.4 million from the beginning of the year. The increase in cash for the first three months of 1998 was the result of $16.3 million provided by operating activities, $4.0 million used for investing activities and $2.9 million used for financing activities. Operating Activities - Net income, depreciation and deferred income taxes and investment tax credits provided $16.2 million. About $.1 million of cash was provided from fluctuations in working capital and other operating activities. Investing Activities - Construction and plant expenditures consumed approximately $3.2 million, while $.8 million was used for C&LM programs and non-utility investments. Financing Activities - Dividends paid on common stock were $2.5 million, while short-term obligations required $.4 million. For related information see the Company's discussion on Financing and Capitalization below. 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. In an effort to achieve a negotiated resolution to the issues surrounding the restructuring of the Vermont electric utility industry, the Company, Green Mountain Power Corporation, the Vermont Department of Public Service (DPS) and representatives of the Governor of the State of Vermont developed a Memorandum of Understanding (MOU) in February 1997 establishing a plan for implementing restructuring in Vermont. That MOU expressly required legislative action to become efficient. Although concepts of the MOU were considered by the Vermont General Assembly, no action was taken on the MOU by the Legislature and the MOU has now lapsed. 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 into affiliate entities that were functionally separate from 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 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 been 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, the bill did not become effective and any efforts to pursue it in the future will require that it be re-enacted by the Vermont Senate and passed by the House. 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 or the MOU. Other legislation intended to advance a portion of the PSB Report and Order and the MOU were also introduced. However, neither the House nor Senate acted on these reforms which must be reintroduced in the next legislative biennium beginning 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, the MOU, S.62 or the House Special Committee report. 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 affirms, clarifies and modifies 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 removes 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. Under the wholesale power purchase contract with the Company, Connecticut Valley may terminate service at the end of a service year, provided it has given written notice of termination prior to the beginning of that service year. Claremont alleges 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 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 from the bench that it reaffirmed its finding of imprudence and would designate 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, 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 from the bench, 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 for the year ended 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 as of December 31, 1997 under SFAS No. 5, "Accounting for Contingencies," representing Connecticut Valley's estimated loss on power contracts for the twelve months following December 31, 1997. 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 issued from the bench, which was continued 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 has 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. Also, on April 3, 1998, the Court indicated its 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 have 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. Subsequently, the NHPUC has filed a motion to dismiss PSNH's pending complaint on which the November hearing is scheduled. The Company has sought leave of Court to file a brief in opposition to this motion. As a result of these Court orders, Connecticut Valley's 1997 charges under SFAS No. 5 and SFAS No. 71 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 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 will exercise all of its remedies from and after May 5, 1998 in the event that the violations are not cured. After reversing the 1997 write-offs described above, Connecticut Valley will be in compliance with the financial covenants associated with its $3.75 million loan with the Bank. As a result, Connecticut Valley has satisfied the Bank's requirements for curing the violation. On May 11, 1998 the NHPUC issued an order requiring the Company 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 has been scheduled in this matter on June 11, 1998. 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 has filed a motion seeking rehearing of the FERC's December 18, 1997 Order. 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. 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 SFAS No. 5 totaling approximately $75.0 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 under SFAS No. 71 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 SFAS No. 5 of approximately $54.9 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 1998. For further information on New Hampshire restructuring issues and other regulatory events in New Hampshire affecting the Company or Connecticut Valley and the December 1997 charges and reversals of the charges, see the Company's Form 8-K dated January 12, 1998, January 28, 1998 and April 1, 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 1997 Form 10-K. The Company has initiated and will continue to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC. The Company cannot predict the ultimate outcome of this matter. However, an adverse resolution could have a material adverse effect on the Company's results of operations, cash flows, and ability to obtain capital at competitive rates. 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 this Quarterly Report on Form 10-Q, the Company believes it currently complies with the provisions of SFAS No. 71 for its regulated retail 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 $73.0 million on a pre-tax basis as of March 31, 1998. 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, 1997, 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 SFAS No. 5. 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 and ability to obtain capital at competitive rates. It is possible that stranded cost exposure associated with SFAS Nos. 5, 71, and 121, before mitigation could exceed the Company's current total common stock equity. FINANCING AND CAPITALIZATION Utility The level of short-term borrowings fluctuates based on seasonal corporate needs, the timing of long-term financings and market conditions. On November 5, 1997 the Company entered into an unsecured $50 million, 364 day committed Revolving Credit and Competitive Advance Facility (Credit Facility) with a group of banks. With the approval of this facility by the PSB on April 2, 1998, it became a three-year facility with two one-year options. However, due to the February 27, 1998 Order issued by the PSB in the Green Mountain Power Corporation rate proceeding, the banks participating in this Credit Facility have determined that a material adverse change occurred in the Company's financial prospects. Such a condition would prevent borrowings under the Credit Facility. Currently, the Company has no borrowings outstanding under this Credit Facility. Negotiations with the banks participating in the Credit Facility have resulted in an understanding, subject to documentation and regulatory approval, of modifications to the Credit Facility. Those major changes are: 1) a second mortgage interest in the Company's Vermont utility fixed assets; 2) a revised maturity date of June 1, 1999 (the original agreement was to end in November 2000); 3) a 25 basis point increase in interest rates on borrowings; 4) the application of any proceeds from the issuance of any First Mortgage Bonds during the term of the Credit Facility to the concurrent repayment of any outstanding loans as well as the reduction of the aggregate commitment of the Credit Facility; and 5) a 25 basis point increase in the cost of $16.3 million aggregate notional amount of letters of credit. Although the Company expects borrowings under the Credit Facility will again become available shortly, it cannot guarantee the availability of the Credit Facility to meet near-term liquidity needs. In December 1998 approximately $20.5 million of long-term debt becomes due and payable. Connecticut Valley maintains a $.8 million committed line of credit for its construction program and for other corporate purposes which expires on May 31, 1998. Interest rates for borrowings under this short-term debt arrangement are 25 basis points less than the prime rate. Connecticut Valley had $250,000 and $625,000 outstanding short-term debt at March 31, 1998 and December 31, 1997, respectively. Connecticut Valley is currently negotiating with Citizens Bank of New Hampshire to extend this facility. The Company's capital structure ratios as of March 31, 1998 (including amounts of long-term debt due within one year) consisted of 53.2% common equity, 7.0% preferred stock and 39.8% long-term debt including capital lease obligations. Current credit ratings of the Company's securities as reaffirmed by Duff & Phelps and Standard & Poor's are as follows: Duff & Standard Phelps & Poor's ------ -------- First Mortgage Bonds BBB A- Corporate Credit Rating BBB Preferred Stock BBB- BBB- On January 22, 1998, Standard & Poor's revised its ratings outlook on the Company to negative from stable stating that the revised outlook reflects the adverse ruling by the NHPUC related to Connecticut Valley discussed above. Non-Utility Catamount, a wholly owned subsidiary of the Company, implemented a credit facility in July 1996 which provides for up to $8.0 million of letters of credit and working capital loans. Currently, a $1.2 million letter of credit is outstanding to support certain of Catamount's obligations in connection with a debt reserve requirement in the Appomattox Cogeneration project. Financial obligations of the non-utility wholly owned subsidiaries are non-recourse to the Company. C&LM Programs The primary purpose of these programs is to offset the need for long-term power supply and delivery resources that are more expensive to purchase or develop than customer-efficiency programs. Total C&LM expenditures in 1997 were $2.7 million and are expected to be $1.7 million for 1998. 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 two projects under construction in Thetford and Fort Dunlop, England, and a project under development in Summersville, West Virginia. Catamount's after-tax earnings were $.7 million and $.5 million for the first quarter of 1998 and 1997, 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. SmartEnergy incurred losses of $.4 million for the first quarter of 1998 and earnings of $.04 million for the same period last year. The 1998 loss results from activities that will allow SmartEnergy to enter several niches of the national and international energy market. SmartEnergy has signed an agreement to manufacture and deliver the SmartDrive dairy vacuum pump control to domestic and worldwide markets beginning later this year. Allies in this venture are Babson Brothers Company and Asea Brown Boveri. 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 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 increasing cost of providing service. Approximately $14.3 million or 92.9% of the rate increase request is 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. New Hampshire: 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 results from higher forecast energy and capacity charges on power Connecticut Valley purchases from the Company plus removal of credit effective during 1997 to refund overcollections from 1996. In an order dated December 31, 1997, the NHPUC 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. For additional information on Vermont and New Hampshire rate and regulatory matters see Electric Industry Restructuring discussed above and Note 3 to the Consolidated Financial Statements. Year 2000 Information Systems Modifications The Company has assessed the impact of the year 2000 issue on its computer systems and applications. During 1997, the Company incurred costs of approximately $.1 million and estimates that about $2.5 million will be incurred in 1998 and $.2 million will be incurred in 1999 to modify its existing computer systems and applications which are expected to be completed during the second quarter of 1999. During the first quarter of 1998, the Company requested an accounting order from the PSB to defer these operating and maintenance costs. The Company believes that based on the current regulatory process, these costs will be recovered through the regulatory process and therefore they do not represent the potential for a material adverse effect on its financial position or results of operations. New Accounting Pronouncement In April 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-5, "Reporting on the Costs of Start-up Activities" (SOP 98-5). SOP 98-5 provides guidance on the financial reporting of start-up costs and organization costs. It requires costs of start-up activities and organization costs to be expensed as incurred and is effective for financial statements for fiscal years beginning after December 15, 1998. The Company believes that the adoption of SOP 98-5 will not have a material impact on the Company's financial position or results of operations. Forward Looking Statements Statements in this report relating to future financial conditions are forward looking statements. Such forward-looking statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors, which may cause the actual results, performances or achievements to differ materially from the future forward- looking statements. Such factors include general economic and business conditions, changes in industry regulation, weather and other factors which are described in further detail in the Company's filings with the Securities and Exchange Commission. CENTRAL VERMONT PUBLIC SERVICE CORPORATION PART II - OTHER INFORMATION Item 1. Legal Proceedings. On July 29, 1996, the Company filed a Declaratory Judgment action in the United States District Court for the District of Vermont. The Complaint names as defendants a number of insurance companies that issued policies to the Company dating from the mid 1940s to the late 1980s. The Company asserts that policies issued by defendants provide coverage for all defense and remediation costs associated with the Cleveland Avenue property, the Bennington Landfill site and the North Clarendon site. With the exception of the North Clarendon site, no further remediation is anticipated. See Note 2 to the Consolidated Financial Statements for related disclosures. 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 5, 1998. (b) To approve the Stock Option Plan for Non-employee Directors: For 8,868,202 Against 906,717 Abstain 253,923 (c) Director elected whose term will expire in year 2001: Votes For Votes Withheld Luther F. Hackett 9,727,252 301,590 Other Directors whose terms will expire in 2000: Frederic H. Bertrand Robert L. Barnett Robert G. Clarke Mary Alice McKenzie Other Directors whose terms will expire in 1999: Patrick J. Martin Rhonda L. Brooks Preston Leete Smith Robert H. Young Item 5. Other Information. (a) On May 5, 1998, Joan F. Gamble was elected Assistant Vice President of Human Resources and Strategic Planning. Item 6. Exhibits and Reports on Form 8-K. (a) List of Exhibits 10. Material Contracts A 10.83 Management Incentive Plan for Executive Officers dated January 1, 1998. A - Compensation related plan, contract or arrangement. 27. Financial Data Schedule. (b) Item 5. Other Events, dated January 12, 1998 re: Connecticut Valley Electric Company Inc. filing a motion for rehearing on the Order dated December 31, 1997. Other Events, dated January 28, 1998 re: The Company obtained from its bondholders sufficient consents to implement the Indenture amendment sought by the Company to eliminate any cross default caused by an insolvency of or default by Connecticut Valley Electric Company Inc. 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 15, 1998 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-31-1998 MAR-31-1998 PER-BOOK 320,175 63,740 75,403 77,981 0 537,299 66,016 45,302 85,613 196,931 18,000 8,054 108,844 0 0 0 20,521 1,000 16,952 1,094 165,903 537,299 83,958 5,432 67,847 73,279 10,679 1,337 12,016 2,625 10,264 486 9,778 6 2,010 16,356 .86 .86
EX-10 3 EXHIBIT 10.83 TO 3-31-98 FORM 10Q EXHIBIT 10.83 - - ------------------- CENTRAL VERMONT PUBLIC SERVICE CORPORATION MANAGEMENT INCENTIVE PLAN Adopted As Of January 1, 1998 I. PURPOSE The Company's executive officers participate in the Company's Management Incentive Plan (the "Incentive Plan"). The purpose of the Incentive Plan is to focus the efforts of the executive team on the achievement of challenging and demanding corporate objectives. When corporate performance attains the specified annual performance objectives, an award is granted. A well-directed incentive plan, in conjunction with competitive salaries, provides a level of compensation which rewards the skills and efforts of the executives commensurate with market comparisons. II. ADMINISTRATION The Incentive Plan will be administered by the Compensation Committee of the Board of Directors (the "Committee"). All Committee actions will be subject to review and approval by the full Board of Directors (the "Board"). At the beginning of each year ("Plan Year"), the Committee will submit to the Board its recommendations for that Plan Year as to (i) the Incentive Plan's Corporate Performance Goals, and (ii) the eligible participants. After the end of each Plan Year, the Committee will report to the Board with respect to achievement of the approved Corporate Performance Goals and individual performance measures for that Plan Year, and will submit to the Board its recommendations as to the appropriate award payment levels for each eligible participant. Recommendations of the Committee, with such modifications as may be made by the Board, will be binding on all participants in the Incentive Plan. III. THE PLAN There is established a financial performance threshold, below which no incentive awards will be paid. The threshold is determined by consolidated earnings per share. The degree to which the consolidated earnings per share target is achieved generates a pool which is available to fund incentive payouts. The pool funds awards, but performance measures must also be met in the following areas to receive an award. Each measure is equally weighted. Consolidated earnings per share. While this measure is used to establish the incentive pool, it is also one of the measures which is assessed in determining distribution of the pool. Customer satisfaction. Measures (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. Based on advice and recommendation from the Chief Executive Officer for those reporting to him. The Committee evaluates the Chief Executive Officer's performance. If the maximum payout on all of the standards were to be achieved, the total award would represent 35% of base salary for the Chief Executive Officer; 25% of base salary for the Chief Financial Officer, Senior Vice President Engineering and Operations, and Vice President for and General Manager for Business Development; 20% for other Vice Presidents, and 15% for Assistant Vice Presidents. IV. Any annual incentive award will consist of cash (50%) and Central Vermont Public Service Corporation stock (50%) which will have a three year vesting restriction. Applicable dividends will be paid on awarded restricted stock prior to vesting. The Board may choose to make awards of non-qualified stock options to designated officers consistent with Plan design and intent. V. AMENDMENTS The Board reserves the right to amend, modify or terminate the Incentive Plan at any time. -----END PRIVACY-ENHANCED MESSAGE-----