-----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, FJ9ozZ4+NZmoWdVxYMmZQb5EDjCxmLo1gTfdOPkXc2KSD/O+ZeqhSgn4BCox5RZP WMcQPZ6CK2gpX5YeZUhkfg== 0000018808-98-000057.txt : 19981118 0000018808-98-000057.hdr.sgml : 19981118 ACCESSION NUMBER: 0000018808-98-000057 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19980930 FILED AS OF DATE: 19981113 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: 98748198 BUSINESS ADDRESS: STREET 1: 77 GROVE ST CITY: RUTLAND STATE: VT ZIP: 05701 BUSINESS PHONE: 8027732711 10-Q 1 FORM 10-Q PERIOD ENDING 9/30/98 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 September 30, 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 October 31, 1998 there were outstanding 11,457,876 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 and nine months ended September 30, 1998 and 1997 3 Consolidated Balance Sheet as of September 30, 1998 and December 31, 1997 4 Consolidated Statement of Cash Flows for the nine months ended September 30, 1998 and 1997 5 Notes to Consolidated Financial Statements 6-12 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 13-30 PART II. OTHER INFORMATION 31 SIGNATURES 32
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 Nine Months Ended September 30 September 30 1998 1997 1998 1997 ------- ------- -------- -------- Operating Revenues $69,522 $67,990 $219,886 $221,926 ------- ------- -------- -------- Operating Expenses Operation Purchased power 42,196 40,114 127,784 121,415 Production and transmission 5,925 6,134 17,279 17,421 Other operation 9,955 9,762 32,808 30,445 Maintenance 3,767 4,187 11,421 10,913 Depreciation 4,145 4,135 12,603 12,824 Other taxes, principally property taxes 2,779 2,394 8,623 8,100 Taxes on income (176) 86 1,837 6,375 ------- ------- -------- -------- Total operating expenses 68,591 66,812 212,355 207,493 ------- ------- -------- -------- Operating Income 931 1,178 7,531 14,433 ------- ------- -------- -------- Other Income and Deductions Equity in earnings of affiliates 808 790 2,384 2,467 Allowance for equity funds during construction 13 9 41 53 Other income, net 741 3,829 1,673 7,575 Provision for income taxes (62) (1,126) - (2,157) ------- ------- -------- -------- Total other income and deductions, net 1,500 3,502 4,098 7,938 ------- ------- -------- -------- Total Operating and Other Income 2,431 4,680 11,629 22,371 Net Interest Expense 2,660 2,615 7,919 7,842 ------- ------- -------- -------- Net Income (Loss) Before Extraordinary Credit (229) 2,065 3,710 14,529 Extraordinary Credit Net of Taxes - - 873 - ------- ------- -------- -------- Net Income (Loss) (229) 2,065 4,583 14,529 Retained Earnings at Beginning of Period 74,646 77,983 75,841 74,137 ------- ------- -------- -------- Cash Dividends Declared Preferred stock 486 507 1,459 1,521 Common stock 48 (21) 5,082 7,583 ------- ------- -------- -------- Total dividends declared 534 486 6,541 9,104 ------- ------- -------- -------- Retained Earnings at End of Period $73,883 $79,562 $ 73,883 $ 79,562 ======= ======= ======== ======== Earnings (Losses) Available For Common Stock $ (715) $ 1,558 $ 3,124 $ 13,008 Average Shares of Common Stock Outstanding 11,448,585 11,423,401 11,432,844 11,470,643 Basic and Diluted Share of Common Stock: Earnings (losses) before extraordinary credit $(.06) $ .14 $.19 $1.13 Extraordinary credit - - .08 - ----- ----- ---- ----- Earnings (Losses) Per Basic and Diluted Share of Common Stock $(.06) $ .14 $.27 $1.13 ===== ===== ==== ===== Dividends Paid Per Share of Common Stock $.22 $.22 $.66 $.66 The accompanying notes are an integral part of these consolidated financial statements.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION CONSOLIDATED BALANCE SHEET (Dollars in thousands) September 30 December 31 1998 1997 ------------ ----------- Assets Utility Plant, at original cost $462,635 $461,482 Less accumulated depreciation 161,689 151,250 -------- -------- 300,946 310,232 Construction work in progress 17,422 10,450 Nuclear fuel, net 847 964 -------- -------- Net utility plant 319,215 321,646 -------- -------- Investments and Other Assets Investments in affiliates, at equity 26,144 26,495 Non-utility investments 36,022 33,736 Non-utility property, less accumulated depreciation 2,979 2,894 -------- -------- Total investments and other assets 65,145 63,125 -------- -------- Current Assets Cash and cash equivalents 10,154 16,506 Special deposits 422 404 Accounts receivable, less allowance for uncollectible accounts ($1,975 in 1998 and $1,946 in 1997) 21,933 23,166 Unbilled revenues 11,067 18,951 Materials and supplies, at average cost 3,890 3,779 Prepayments 4,781 1,464 Other current assets 5,509 4,970 -------- -------- Total current assets 57,756 69,240 -------- -------- Regulatory Assets 70,045 73,209 -------- -------- Other Deferred Charges 5,020 4,720 -------- -------- Total Assets $517,181 $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 45,312 45,295 Treasury stock (327,972 shares and 362,447 shares, respectively, at cost) (4,277) (4,728) Retained earnings 73,883 75,841 -------- -------- Total common stock equity 185,633 187,123 Preferred and preference stock 8,054 8,054 Preferred stock with sinking fund requirements 18,000 19,000 Long-term debt 108,834 93,099 Long-term lease arrangements 16,412 17,223 -------- -------- Total capitalization 336,933 324,499 -------- -------- Current Liabilities Short-term debt - 12,650 Current portion of long-term debt and preferred stock 21,521 24,271 Accounts payable 5,719 4,609 Accounts payable - affiliates 9,922 12,441 Accrued income taxes - 6,631 Dividends declared 486 2,513 Nuclear decommissioning costs 6,012 6,010 Other current liabilities 18,375 21,646 -------- -------- Total current liabilities 62,035 90,771 -------- -------- Deferred Credits Deferred income taxes 56,152 53,996 Deferred investment tax credits 6,927 7,222 Nuclear decommissioning costs 24,722 28,947 Other deferred credits 30,412 26,505 -------- -------- Total deferred credits 118,213 116,670 -------- -------- Total Capitalization and Liabilities $517,181 $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) Nine Months Ended September 30 1998 1997 ------- ------- Cash Flows Provided (Used) By Operating Activities Net income $ 4,583 $14,529 Adjustments to reconcile net income to net cash provided by operating activities Extraordinary credit (1,294) - Equity in earnings of affiliates (2,383) (2,467) Dividends received from affiliates 2,595 2,316 Equity in earnings of non-utility investments (5,094) (3,905) Distribution of earnings from non-utility investments 2,953 2,935 Depreciation 12,603 12,824 Deferred income taxes and investment tax credits 2,427 (691) Allowance for equity funds during construction (41) (53) Net deferral and amortization of nuclear refueling replacement energy and maintenance costs (2,838) 4,045 Amortization of conservation and load management costs 4,226 5,264 Gain on sale of investment - (2,891) Gain on sale of property - (2,095) Decrease in accounts receivable and unbilled revenues 9,485 12,207 Increase (decrease) in accounts payable (941) (2,043) Increase (decrease) in accrued income taxes (9,606) (1,316) Change in other working capital items (4,411) 3,027 Other, net 3,768 (4,684) ------- ------- Net cash provided by operating activities 16,032 37,002 ------- ------- Investing Activities Construction and plant expenditures (11,550) (10,742) Deferred conservation & load management expenditures (1,857) (1,065) Return of capital 140 140 Proceeds from sale of investment - 3,750 Proceeds from sale of property - 2,624 Non-utility investments (102) (777) Special deposits - 2,284 Other investments, net (234) 74 ------- ------- Net cash used for investing activities (13,603) (3,712) ------- ------- Financing Activities Sale (repurchase) of common stock 451 (1,072) Short-term debt, net (650) (5,764) Long-term debt, net (15) - Common and preferred dividends paid (8,513) (9,103) Other (54) - ------- ------- Net cash used for financing activities (8,781) (15,939) ------- ------- Net Increase (Decrease) in Cash and Cash Equivalents (6,352) 17,351 Cash and Cash Equivalents at Beginning of Period 16,506 6,365 ------- ------- Cash and Cash Equivalents at End of Period $10,154 $23,716 ======= ======= Supplemental Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) $ 5,534 $ 5,017 Income taxes (net of refunds) $ 9,940 $10,398 The accompanying notes are an integral part of these consolidated financial statements.
CENTRAL VERMONT PUBLIC SERVICE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS September 30, 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 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. 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 received last month 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 is in the process of responding to the State's request. The Company's response will include the identification of 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 .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 has had no involvement with these sites for over five years. Additional information on these sites is available in the Company's Annual Report on Form 10-K. 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 alleged 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 were reached with all of the defendants. The settlements varied with respect to the scope of the release granted by the Company. Due to the uncertainties associated with the actual clean-up costs, no income has been recognized, instead, 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 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 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 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 () 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 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 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 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 prospects for 1998 will be adversely affected. In an effort to mitigate eroding earnings and cash flow prospects during the Vermont Supreme Court review process, on June 12, 1998 the Company filed with the PSB a request for a 10.7% rate increase ($24.7 million of annualized revenues) effective March 1, 1999. This rate case proceeding overlaps 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, if approved by the PSB, 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. The temporary rate increase is subject to adjustment upon future resolution of the Hydro-Quebec Contract issues presently before the VSC. 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. Upon approval of the agreement by the PSB, the Company will record a charge of approximately $7.4 million on a pre-tax basis for disallowed purchased power expenses. The Company anticipates the PSB's decision on the rate increase agreement during the fourth quarter of 1998 and a resolution of the Hydro-Quebec Contract issues by the end of 1999. If the Company receives an unfavorable ruling from the VSC, and the methodology used to determine the temporary Hydro-Quebec disallowance is continued 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. Such a result would jeapordize the Company's ability to continue as a going concern. 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. 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 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 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 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 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 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. The NHPUC's request for a stay was denied. 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. 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 Federal Court's June 5, 1998 Order, discussed below. On June 5, 1998, the Court issued an Order which denied the NHPUC's motion for a stay of the Court's preliminary injunction. The Order clearly states that no restructuring effort in New Hampshire can move forward without the Court's approval unless all New Hampshire utilities agree to the plan. The Order suspends all involuntary restructuring efforts for all New Hampshire utilities until a hearing on the merits is conducted. The Company believes that the Court will convert the preliminary injunction to a permanent injunction after a hearing which is expected to occur during the first half of 1999. The NHPUC has appealed this Order to the Circuit Court of Appeals. These appeals have been fully briefed, and the Court of Appeals conducted oral argument on October 6, 1998. 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 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 has satisfied the Bank's requirements for curing the violation. 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. 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 tranmission 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 will submit supplemental testimony on Phase 2 issues in December 1998. 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 1999. The Company has initiated 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. The Company cannot predict the ultimate outcome of this matter. However, an adverse resolution would have a material adverse effect on the Company's results of operations, cash flows, and ability to obtain capital at competitive rates. Either of these reasonably possible outcomes could occur during calendar year 1999. 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 Nine Months Ended September 30 September 30 1998 1997 1998 1997 ------- ------- -------- -------- Operating revenues $43,186 $41,967 $152,269 $126,771 Operating income $ 3,929 $ 3,526 $ 11,639 $ 10,816 Net income $ 1,816 $ 1,721 $ 5,324 $ 5,244 Company's equity in net income $594 $548 $1,643 $1,649
CENTRAL VERMONT PUBLIC SERVICE CORPORATION Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS September 30, 1998 Earnings Overview The Company recorded a net loss of $.2 million, or a loss of $.06 per share of common stock for the third quarter of 1998, compared to net income of $2.1 million, or $.14 per share of common stock during the same period last year. Due to the Company's winter sales peak and higher winter rates, the Company normally experiences losses in the second and third quarters when sales are lower and rates are reduced. Lower third quarter 1998 earnings compared to the third quarter of 1997 resulted primarily from higher net power costs during the 1998 quarter and an after tax gain of approximately $1.8 million or $.16 per share of common stock from a non-recurring asset sale recorded in 1997. For the nine months ended September 30, 1998, net income was $4.6 million, or $.27 per share of common stock compared to $14.5 million, or $1.13 per share of common stock for the 1997 period. Included in net income and earnings per share of common stock in the first nine months of 1998 is the positive impact of the reversal of a fourth quarter 1997 charge of $3.6 million (after-tax) and $.31, respectively, and an after-tax extraordinary credit of $.9 million and $.08, respectively, at the Company's New Hampshire utility subsidiary, Connecticut Valley Electric Company Inc. Net income and earnings per share of common stock for the first nine months of 1997 reflect after-tax gains of $3.1 million and $.28, respectively, from non-recurring asset sales. Absent the 1998 reversal of the fourth quarter 1997 charge of $3.6 million and the extraordinary credit of $.9 million, 1998's first nine months net income would have been $.1 million, or a loss of $.12 per share of common stock. Net income for the first nine months of 1997 absent non-recurring asset sales was $11.4 million, or $.85 per share of common stock. Other factors affecting results for 1998 are described in results of operations below. On June 12, 1998, the Company filed with the PSB a request for a 10.7% rate increase ($24.7 million of annualized revenues) effective March 1, 1999. On October 27, 1998, the Company reached an agreement with the DPS regarding this rate increase request. The agreement, if approved by the PSB, 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. The temporary rate increase is subject to adjustment upon future resolution of the Hydro-Quebec Contract issues presently before the VSC discussed in Note 3, Retail Rates above. Operating Revenues and MWH Sales A summary of MWH sales and operating revenues for the three and nine months ended September 30, 1998 and 1997 (and the related percentage changes from 1997) is set forth below:
Three Months Ended September 30 ------------------------------------------------ Percentage Percentage MWH Increase Revenues (000's) Increase 1998 1997 (Decrease) 1998 1997 (Decrease) ------- ------- ---------- ------- ------- ---------- Residential 215,475 213,402 1.0 $24,894 $24,744 .6 Commercial 242,033 234,354 3.3 24,310 23,913 1.7 Industrial 99,229 99,945 (.7) 6,888 6,997 (1.6) Other retail 1,799 1,816 (.9) 488 496 (1.6) ------- ------- ------- ------- Total retail sales 558,536 549,517 1.6 56,580 56,150 .8 ------- ------- ------- ------- Resale sales: Firm 492 258 90.7 24 11 118.2 Entitlement 93,320 91,983 1.5 4,562 4,458 2.3 Other 264,571 217,214 21.8 7,145 6,018 18.7 ------- ------- ------- ------- Total resale sales 358,383 309,455 15.8 11,731 10,487 11.9 ------- ------- ------- ------- Other revenues - - - 1,211 1,353 (10.5) ------- ------- ------- ------- Total sales 916,919 858,972 6.7 $69,522 $67,990 2.3 ======= ======= ======= ======= Nine Months Ended September 30 --------------------------------------------------- Percentage Percentage MWH Increase Revenues (000's) Increase 1998 1997 (Decrease) 1998 1997 (Decrease) --------- --------- ---------- -------- -------- ---------- Residential 692,304 705,862 (1.9) $ 84,499 $ 85,032 (.6) Commercial 694,801 680,489 2.1 74,953 76,451 (2.0) Industrial 307,647 314,501 (2.2) 24,344 24,805 (1.9) Other retail 5,364 5,365 - 1,457 1,455 .1 --------- --------- -------- -------- Total retail sales 1,700,116 1,706,217 (.4) 185,253 187,743 (1.3) --------- --------- -------- -------- Resale sales: Firm 1,617 755 114.2 61 34 79.4 Entitlement 229,076 287,469 (20.3) 14,825 14,025 5.7 Other 578,741 599,792 (3.5) 15,966 15,795 1.1 --------- --------- -------- -------- Total resale sales 809,434 888,016 (8.8) 30,852 29,854 3.3 --------- --------- -------- -------- Other revenues - - - 3,781 4,329 (12.7) --------- --------- -------- -------- Total sales 2,509,550 2,594,233 (3.3) $219,886 $221,926 (.9) ========= ========= ======== ========
Retail MWH sales for the third quarter of 1998 increased 1.6% compared to the third quarter of 1997 resulting in an .8% increase in retail revenues. For the nine months ended September 30, 1998, retail MWH sales were relatively flat compared to the same period last year, decreasing only about .4%. This minimal decrease resulted in a $2.5 million, or 1.3% decrease in retail revenues. This negative variance is attributable to a $.6 million impact of lower MWH sales in the first nine months of 1998 as compared to the first nine months of 1997 and $1.9 million resulting from a modified rate design reflected in bills rendered since April 1, 1997. 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. Entitlement MWH sales increased 1.5% or 1,337 MWH for the third quarter compared to the same period in 1997. The increase results primarily from increased sales to UNITIL and Hydro-Quebec under Schedule C1 Contract. For the nine months ended September 30, 1998, entitlement MWH sales decreased 20.3% and related revenues increased 5.7%, or $.8 million compared to the same period last year. The decrease results primarily from the scheduled refueling and maintenance outage of the Vermont Yankee plant, which extended from March 21, 1998 through June 3, 1998, reducing MWH sales to UNITIL. However, the higher costs of the Company's share of Vermont Yankee's capacity costs associated with the refueling and maintenance outage are passed on to entitlement customers resulting in an increase in entitlement revenues of $.8 million, or 5.7%. The increase in other resale sales and revenues for the third quarter of 1998 resulted primarily from increased short-term system capacity sales partially offset by lower off-system sales. The decrease in other resale sales for the nine months ended September 30, 1998 resulted primarily from decreased off-system sales and sales to Nepool partially offset by an increase in short-term system capacity sales. However, due to market fluctuations, other resale revenues increased $.2 million, or 1.1%. The decrease on other revenues for the three and nine months ended September 30, 1998 compared to the same periods last year results primarily from lower revenues associated with a transmission interconnection agreement and pole attachment rentals. Net Purchased Power and Production Fuel Costs The net cost components of purchased power and production fuel costs for the three and nine months ended September 30, 1998 and 1997 are as follows (dollars in thousands):
Three Months Ended September 30 -------------------------------------------- 1998 1997 Units Amount Units Amount ------- ------- ------- ------- Purchased and produced: Capacity (MW) 543 $24,106 536 $23,703 Energy (MWH) 869,234 18,090 862,357 16,411 ------- ------- Total purchased power costs 42,196 40,114 Production fuel (MWH) 96,602 612 42,799 518 ------- ------- Total purchased power and production fuel costs 42,808 40,632 Entitlement and other resale sales (MWH) 357,891 11,707 309,197 10,476 ------- ------- Net purchased power and production fuel costs $31,101 $30,156 ======= ======= Nine Months Ended September 30 ---------------------------------------------- 1998 1997 Units Amount Units Amount --------- ------- --------- ------- Purchased and produced: Capacity (MW) 559 $71,221 571 $68,161 Energy (MWH) 2,408,734 56,563 2,567,333 53,254 ------- ------- Total purchased power costs 127,784 121,415 Production fuel (MWH) 243,214 1,521 174,855 1,209 ------- ------- Total purchased power and production fuel costs 129,305 122,624 Entitlement and other resale sales (MWH) 807,817 30,791 887,261 29,820 ------- ------- Net purchased power and production fuel costs $98,514 $92,804 ======= =======
Net purchased power and production fuel costs increased $.9 million, or 3.1% for the third quarter of 1998 compared to the third quarter of 1997. This variance is mostly attributable to increased purchases from small power qualifying and higher costs under the Hydro-Quebec power contract. For the nine months ended September 30, 1998, net purchased power and production fuel costs increased $5.7 million, or 6.2% compared to the same period last year. However, absent the benefit of the 1997 Connecticut Valley reversal discussed above, net purchased power and production fuel costs increased $11.2 million, or 12.1% for 1998 compared to the same period last year primarily as the result of the Vermont Yankee extended outage, increased purchases from small power qualifying and higher costs under the Hydro-Quebec power contract. Pursuant to a Vermont Public Service Board (PSB) Accounting Order, first half 1997 energy costs were reduced by approximately $5.8 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. 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 (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 are approximately $1.0 million on a pre-tax basis. Such amounts have not been paid or expended at this time. NUCLEAR MATTERS The Company maintains a 1.7303% joint-ownership interest in 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 interests in Maine Yankee, Yankee Atomic and Vermont Yankee, respectively. Millstone Unit #3 Millstone Unit #3 (Unit #3) received approval by the NRC commissioners and NRC staff on June 15, 1998 and June 29, 1998, respectively, to restart Unit #3 which was shut down on March 30, 1996, due to numerous technical and non-technical problems. Unit #3 reached full power operation on July 14, 1998. The Company's share of the total incremental operating and maintenance costs for Unit #3 were about $.9 million for 1997 and about $.3 million for 1998. Incremental replacement power costs for 1998 were about $1.9 million for the six month period that Unit #3 was out of service. 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 returned to service on June 3, 1998. The refueling outage extended twenty-six days beyond the scheduled forty-nine days. The Company incurred approximately $3.1 million and $6.5 million for replacement energy and maintenance costs, respectively, of which $7.2 million in total was deferred consistent with current accounting and ratemaking practices. 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 $6.2 million. Such costs will be deferred by Vermont Yankee and amortized over the remaining license life of the plant. Vermont Yankee has received expressions of interest to purchase Vermont Yankee. Discussions between Vermont Yankee and these parties are continuing. 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 $16.0 million, $12.0 million and $3.9 million, respectively. 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 three 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. 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 Federal approval by five 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. Other Operation Other operating expenses increased $2.4 million for the nine months ended September 30, 1998 principally due to an increase in distribution, consulting services and regulatory commission expenses partially offset by an increase in deferral of conservation and load management costs. Maintenance Maintenance expenses for the three months ended September 30, 1998 decreased $.4 million compared to the same period in 1997 primarily due to Unit #3 being back on line. The increase in maintenance expenses of $.5 million for the nine months ended September 30, 1998 compared to the same period in 1997 is mostly attributable to the severe ice storm in January 1998 partially offset by lower maintenance costs related to Unit #3. Income Taxes Federal and state income taxes fluctuate with the level of pre-tax earnings. The decrease in total income tax expense for the three and nine months ended September 30, 1998 results primarily from a decrease in pre-tax earnings for the periods. Other Income and Deductions The decrease in other income, net for the 1998 three and nine months periods results from lower subsidiaries' earnings (see Diversification below) and gains of $2.1 million and $2.9 million from non-recurring asset sales in February and August 1997, respectively. 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 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 was $16.0 million and $37.0 million for the nine months ended September 30, 1998 and 1997, respectively. The reduction is due to reduced cash earnings, the extended refueling outage at the Vermont Yankee Nuclear Power Plant in the 1998 period, and higher tax payments. The Company ended the first nine months of 1998 with cash and cash equivalents of $10.2 million, a decrease of $6.4 million from the beginning of the year. The decrease in cash for the first nine months of 1998 was the result of $16.0 million provided by operating activities, offset by $13.6 million used for investing activities and $8.8 million used for financing activities. Operating Activities - Net income, depreciation and deferred income taxes and investment tax credits provided $19.6 million. About $3.6 million of cash was used for working capital needs and other operating activities. Investing Activities - Construction and plant expenditures consumed approximately $11.6 million, while $2.0 million was used for C&LM programs and non-utility investments. Financing Activities - Dividends paid on common stock were $7.0 million while preferred dividends were $1.5 million. Short-term obligations required $.7 million and sale of Treasury Stock provided $.4 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 which matures on June 1, 1999. No borrowings were outstanding at September 30, 1998 but borrowings are expected to be in the range of $10.0 to $15.0 million by June 1, 1999 as a result of scheduled first mortgage bond maturities. In addition, the Company must rollover an aggregate of $16.3 million of letters of credit between May 1999 and December 1999. The Company's ability to extend or replace the maturing $50.0 million revolving credit facility and roll over $16.3 million of maturing letters of credit will be dependent in large part on a positive outcome of the pending Hydro-Quebec Contract issues at the VSC. Connecticut Valley has outstanding long-term bank debt of $3.75 million expiring December 27, 1999. Discussions continue between Connecticut Valley and the Bank to extend this facility and to re-establish the $.8 million committed line of credit which expired on May 31, 1998. The Company's capital structure ratios as of September 30, 1998 (including amounts of long-term debt and preferred stock due within one year) consisted of 51.8% common equity, 7.5% preferred stock and 40.7% 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. Catamount, a wholly owned non-utility subsidiary of the Company, has a credit facility 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. Hydro-Quebec Contract The Company is a party to a power contract with Hydro-Quebec through the VJO, a consortium of Vermont utilities. Under the contract with Hydro-Quebec and a separate Vermont Participants Agreement, 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 partipants, including the Company, will "step up" to the defaulting party's share on a pro-rata basis. As of September 30, 1998 the Company's VJO obligation is approximately 47% of the total contract. On November 6, 1998, in connection with a severe ice storm during January 1998, the VJO filed a Notice of Arbitration in which it sets forth grounds for termination of the Hydro-Quebec contract that include, among others, several material defaults on the part of Hydro-Quebec with respect to the construction, maintenance and design of its transmission system. The contract provides that the arbitration will be conducted in Burlington, Vermont and under the auspices of the American Arbitration Association. Diversification Catamount was formed for the purpose of investing in non-regulated power plant projects. Currently, Catamount, through its wholly owned subsidiaries, has interests in six operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; Hopewell, Virginia; and Thetford, England. In addition, Catamount has interests in a project under construction in Fort Dunlop, England, and a project under development in Summersville, West Virginia. Catamount's after-tax earnings were $.8 million and $2.6 million for the third quarter of 1998 and 1997, respectively, and $2.1 million and $3.6 million for the first nine months 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 and $.2 million for the third quarter of 1998 and 1997, respectively, and losses of $1.2 million and $.2 million for the first nine months of 1998 and 1997, respectively. These losses are associated with activities that are intended to position SmartEnergy for possible entry into several niches of national retail markets. SmartEnergy has signed an agreement to manufacture and deliver the SmartDrive dairy vacuum pump control to domestic and worldwide markets beginning later this year. Participants in this arrangement 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. 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 overlaps the 6.6% rate increase request referenced above that is now stayed pending a review on the so-called preclusion issue by the Vermont Supreme Court. On October 27, 1998, the Company reached an agreement with the DPS regarding the 10.7% rate increase request. The agreement, if approved by the PSB, 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. The temporary rate increase is subject to adjustment upon future resolution of the Hydro-Quebec Contract issues presently before the VSC. In addition, the agreement incorporates a pro forma 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. The Company anticipates the PSB's decision on the agreement during the fourth quarter of 1998 and a resolution of the Hydro-Quebec contracts issues by the end of 1999. If the Company receives an unfavorable ruling from the VSC, and the methodology used to determine the temporary Hydro-Quebec disallowance is continued 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 result would jeapordize the ability of the Company to continue as a going concern. 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. Management Audit On April 17, 1997, the PSB ordered an independent forward-looking analysis of three of the Company's management policies and practices focusing on three areas: 1) Transmission of information to the Company's Board of Directors by management. 2) Cost-benefit analyses for major corporate decisions. 3) Implementation of the Company's ethics and conflict of interest policy. The PSB's consultant began work on the project during the first quarter of 1998 and issued a final report during October 1998. The PSB has not yet indicated any response to the report. Proposed Formation of Holding Company In order to further prepare Central Vermont Public Service Corporation for deregulation, on July 24, 1998, the Company filed a petition with the PSB for permission to create a holding company that would have as subsidiaries the Company and non-utility subsidiaries-Catamount and SmartEnergy. The Company believes that a holding company structure will facilitate the Company's transition to a deregulated electricity market. The proposed holding company formation must also be approved by Federal regulators, including the Securities and Exchange Commission and the FERC, and by the holders of the Company's shareholders. 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 continues to evaluate the impact that the adoption of SOP 98-5 will have on the Company's financial position or results of operations. 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 and assessment activities are 100% complete. Overall remediation efforts are estimated at approximately 50% complete. The Company expects to achieve compliance with Year 2000 requirements for all of its financial and operating systems during 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 September 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 June 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 would have a material adverse effect on the Company's results of operations, liquidity 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 interruptions of power supply and transmission. The Company is part of the Northeast grid contingency plan that would go into effect immediately which will 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. In addition, the State of Vermont has developed a contingency plan that deals with electrical emergencies. The Company believes it will incur approximately $2.8 million of costs associated with making the necessary modifications to its centralized and non-centralized computer systems. As of September 30, 1998, approximately $1.7 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 these costs and amortize them over a five-year period beginning January 1, 2000. The Company believes that these costs will be recovered through the regulatory process and do not represent the potential for a material adverse effect on its financial position or results of operations. 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 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 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. Other legislation intended to advance a portion of the PSB Report and Order was 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, S.62 or the House Special Committee report. On July 22, 1998, Governor Dean issued an Executive Order establishing a Working Group On Vermont' Electricity Future to lead a new effort to review the issues of potential restructuring of Vermont's electric industry. Members of the Working Group include individuals with both business and governmental experience including a former chairman of the PSB. The purpose of the Working Group is to determine the best structure for the electric industry in Vermont so as to achieve the lowest current and long-term electric costs for all classes of electric consumers. While any recommendations developed through this effort cannot be implemented without regulatory and/or legislative enactments, the Governor has expressed that he hopes that the creation of the Working Group will provide an independent, non-partisan, fact-based analysis and examination of the issues surrounding electric restructuring and help pave the way to some type of proposal to pass the 1999 Vermont General Assembly. The Working Group is charged with presenting a report, with recommendations, to the Governor and Legislative leaders by December 15, 1998. In the months since its establishment, the Working Group has convened a series of meetings and engaged in fact finding with interested parties, including Vermont utilities. At this time, the task force has yet to issue a preliminary report of its recommendations. 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 paper were filed and a technical conference was convened with the PSB to recommend the scope of the investigation and potential courses for reform of Vermont's power supply. As of this time, the PSB has yet to act on any of the proposal or recommendations made concerning the disposition of the matters in Docket No. 6140. In order to further prepare Central Vermont Public Service Corporation for deregulation, on July 24, 1998, the Company filed a petition with the PSB for permission to create a holding company that would have as subsidiaries the Company and non-utility subsidiaries-Catamount and SmartEnergy. The Company believes that a holding company structure will facilitate the Company's transition to a deregulated electricity market. The proposed holding company formation must also be approved by Federal regulators, including the Securities and Exchange Commission and the FERC, and by the Company's shareholders. 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. 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 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 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 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. In compliance with that 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. The NHPUC's request for a stay was denied. 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. 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 Federal 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 suspends all involuntary restructuring efforts for all New Hampshire utilities until a hearing is conducted. The Company believes that the Court will convert the preliminary injunction to a permanent injunction. The NHPUC has appealed this Order to the Circuit Court of Appeals. These Appeals have been fully briefed, and the Court of Appeals conducted oral argument on October 6, 1998. 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 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 has satisfied the Bank's requirements for curing the violation. 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. 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 tranmission 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 will submit supplemental testimony on Phase 2 issues on December 3, 1998. 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. 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. The Company cannot predict the ultimate outcome of this matter. However, an adverse resolution would 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 $70.0 million on a pre-tax basis as of September 30, 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 September 30, 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 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. 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 July 29, 1996, the Company filed a Declaratory Judgment action in the United States District Court for the District of Vermont. The Complaint named as defendants a number of insurance companies that issued policies to the Company dating from the mid 1940s to the late 1980s. The Company asserted 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. Settlement has been reached with all defendants. 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, 3 and 4. None. Item 5. Other Information. Effective November 2, 1998, Janice L. Scites was elected to the Company's Board of Directors to replace Delano E. Lewis. Item 6. Exhibits and Reports on Form 8-K. (a) List of Exhibits 27. Financial Data Schedule. (b) Item 5. There were no reports on Form 8-K for the quarter ended September 30, 1998. 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 November 13, 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 9-MOS DEC-31-1998 SEP-30-1998 PER-BOOK 319,215 65,145 57,756 75,065 0 517,181 66,438 45,312 73,883 185,633 18,000 8,054 108,834 0 0 0 20,521 1,000 16,412 1,094 157,633 517,181 219,886 1,837 210,518 212,355 7,531 4,098 11,629 7,919 4,583 1,459 3,124 5,082 6,030 16,032 .27 .27
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