-----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, PQSSAif0EmmmaCasZQ4PFV2Xwpsz1JNO+9zDKsaQcNUgS1o1WIkF0Ox92/1pcKqF uKthqTzSNJyJ22wUBIUmKA== 0000018808-97-000016.txt : 19971126 0000018808-97-000016.hdr.sgml : 19971126 ACCESSION NUMBER: 0000018808-97-000016 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19970930 FILED AS OF DATE: 19971113 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CENTRAL VERMONT PUBLIC SERVICE CORP CENTRAL INDEX KEY: 0000018808 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 030111290 STATE OF INCORPORATION: VT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-08222 FILM NUMBER: 97715610 BUSINESS ADDRESS: STREET 1: 77 GROVE ST CITY: RUTLAND STATE: VT ZIP: 05701 BUSINESS PHONE: 8027732711 10-Q 1 FORM 10-Q PERIOD ENDING 9/30/97 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, 1997 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, 1997 there were outstanding 11,423,401 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, 1997 and 1996 3 Consolidated Balance Sheet as of September 30, 1997 and December 31, 1996 4 Consolidated Statement of Cash Flows for the nine months ended September 30, 1997 and 1996 5 Notes to Consolidated Financial Statements 6-9 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 10-23 PART II. OTHER INFORMATION 24 SIGNATURES 25
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 1997 1996 1997 1996 Operating Revenues $67,990 $63,833 $221,926 $209,469 Operating Expenses Operation Purchased power 40,114 37,063 121,415 110,774 Production and transmission 6,134 5,615 17,421 15,307 Other operation 9,762 10,030 30,445 27,650 Maintenance 4,187 4,203 10,913 10,620 Depreciation 4,135 4,511 12,824 13,391 Other taxes, principally property taxes 2,394 2,657 8,100 8,123 Taxes on income 86 (520) 6,375 7,698 _______ _______ _______ _______ Total operating expenses 66,812 63,559 207,493 193,563 _______ _______ _______ _______ Operating Income 1,178 274 14,433 15,906 _______ _______ _______ _______ Other Income and Deductions Equity in earnings of affiliates 790 807 2,467 2,460 Allowance for equity funds during construction 9 31 53 79 Other income, net 3,633 658 7,007 2,345 Benefit (provision) for income taxes (1,126) (80) (2,157) 88 _______ _______ _______ _______ Total other income and deductions, net 3,306 1,416 7,370 4,972 _______ _______ _______ _______ Total Operating and Other Income 4,484 1,690 21,803 20,878 _______ _______ _______ _______ Net Interest Expense 2,419 2,475 7,274 7,352 _______ _______ _______ _______ Net Income (Loss) 2,065 (785) 14,529 13,526 Retained Earnings at Beginning of Period 77,983 72,553 74,137 66,422 _______ _______ _______ _______ 80,048 71,768 88,666 79,948 Cash Dividends Declared Preferred stock 507 507 1,521 1,521 Common stock (21) - 7,583 7,166 _______ _______ _______ _______ Total dividends declared 486 507 9,104 8,687 _______ _______ _______ _______ Retained Earnings at End of Period $79,562 $71,261 $ 79,562 $ 71,261 ======== ======= ======== ======== Earnings (Losses) Available for Common Stock $ 1,558 $(1,292) $13,008 $12,005 Average Shares of Common Stock Outstanding 11,423,401 11,519,748 11,470,643 11,552,140 Earnings (Losses) Per Share of Common Stock $ .14 $(.11) $1.13 $1.04 Dividends Paid Per Share of Common Stock $ .22 $ .22 $ .66 $ .62
CENTRAL VERMONT PUBLIC SERVICE CORPORATION CONSOLIDATED BALANCE SHEET (Dollars in thousands) (Unaudited) September 30 December 31 1997 1996 Assets Utility Plant, at original cost $465,467 $461,231 Less accumulated depreciation 156,650 146,539 ________ ________ 308,817 314,692 Construction work in progress 13,243 9,302 Nuclear fuel, net 965 947 ________ ________ Net utility plant 323,025 324,941 ________ ________ Investments and Other Assets Investments in affiliates, at equity 26,741 26,630 Non-utility investments 30,271 27,823 Non-utility property, less accumulated depreciation 2,872 4,498 ________ ________ Total investments and other assets 59,884 58,951 ________ ________ Current Assets Cash and cash equivalents 23,716 6,365 Special deposits 3,381 5,633 Accounts receivable 13,132 21,878 Unbilled revenues 6,272 11,673 Materials and supplies, at average cost 3,689 3,690 Prepayments 2,607 2,423 Other current assets 3,994 3,840 ________ ________ Total current assets 56,791 55,502 ________ ________ Regulatory Assets and Other Deferred Charges 71,898 63,574 ________ ________ Total Assets $511,598 $502,968 ======== ======== 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 45,290 45,273 Treasury stock (362,447 shares and 266,100 shares, respectively, at cost) (4,728) (3,656) Retained earnings 79,562 74,137 ________ ________ Total common stock equity 190,839 186,469 Preferred and preference stock 8,054 8,054 Preferred stock with sinking fund requirements 20,000 20,000 Long-term debt 117,374 117,374 Long-term lease arrangements 17,493 18,304 ________ ________ Total capitalization 353,760 350,201 ________ ________ Current Liabilities Short-term debt - 5,750 Current portion of long-term debt 3,001 3,015 Accounts payable 3,699 4,432 Accounts payable - affiliates 10,627 12,109 Accrued income taxes 1,148 2,552 Dividends declared 507 507 Other current liabilities 27,422 24,184 ________ ________ Total current liabilities 46,404 52,549 ________ ________ Deferred Credits Deferred income taxes 56,871 57,463 Deferred investment tax credits 7,319 7,612 Other deferred credits 47,244 35,143 ________ ________ Total deferred credits 111,434 100,218 ________ ________ Total Capitalization and Liabilities $511,598 $502,968 ======== ========
CENTRAL VERMONT PUBLIC SERVICE CORPORATION CONSOLIDATED STATEMENT OF CASH FLOWS (Dollars in thousands) (Unaudited) Nine Months Ended September 30 1997 1996 Cash Flows Provided (Used) By Operating Activities Net income $14,529 $13,526 Adjustments to reconcile net income to net cash provided by operating activities Depreciation 12,824 13,391 Deferred income taxes and investment tax credits (691) 554 Allowance for equity funds during construction (53) (79) Net deferral and amortization of nuclear refueling replacement energy and maintenance costs 4,045 (1,393) Amortization of conservation and load management costs 5,264 3,896 Gain on sale of investment (2,891) - Gain on sale of property (2,095) (700) Decrease in accounts receivable 12,207 11,999 Increase(decrease) in accounts payable (2,043) 2,878 Decrease in accrued income taxes (1,316) (2,117) Change in other working capital items 5,311 3,408 Other, net (4,684) (2,833) ________ ________ Net cash provided by operating activities 40,407 42,530 ________ ________ Investing Activities Construction and plant expenditures (10,742) (14,813) Deferred conservation and load management expenditures (1,065) (1,158) Investments in affiliates (11) (99) Proceeds from sale of investment 3,750 - Proceeds from sale of property 2,624 775 Non-utility investments (1,747) (1,079) Other investments, net 74 (158) ________ ________ Net cash used for investing activities (7,117) (16,532) ________ ________ Financing Activities Repurchase of common stock (1,072) (1,042) Sale of treasury stock - 14 Short-term debt, net (5,764) (13,490) Long-term debt, net - 1,236 Common and preferred dividends paid (9,103) (8,686) ________ ________ Net cash used for financing activities (15,939) (21,968) ________ ________ Net Increase in Cash and Cash Equivalents 17,351 4,030 Cash and Cash Equivalents at Beginning of Period 6,365 11,962 ________ ________ Cash and Cash Equivalents at end of Period $23,716 $15,992 ======== ======== Supplemental Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) $ 5,017 $ 5,011 Income taxes (net of refunds) $10,398 $ 7,999
CENTRAL VERMONT PUBLIC SERVICE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS September 30, 1997 Note 1 - Accounting Policies The Company's significant accounting policies are described in Note 1 of Notes to Consolidated Financial Statements included in its 1996 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. 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 will likely result in any material environmental liabilities to the Company. The Company is an amalgamation of more than 100 predecessor companies. Those companies engaged in various operations and activities prior to being merged into the Company. At least two of these companies were involved in the production of gas from coal to sell and distribute to retail customers at three different locations. These activities were discontinued by the Company in the late 1940's or early 1950's. The coal gas manufacturers, other predecessor companies, and the Company itself may have engaged in waste disposal activities which, while legal and consistent with commercially accepted practices at the time, may not meet modern standards and thus represent potential liability. The Company continues to investigate, evaluate, monitor and, where appropriate, remediate contaminated sites related to these historic activities. The Company's policy is to accrue a liability for those sites where costs for remediation, monitoring and other future activities are probable and can be reasonably estimated. 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 Legal Proceedings below. CLEVELAND AVENUE PROPERTY One such site is the Company's Cleveland Avenue property located in the City of Rutland, Vermont, a site where one of its predecessors operated a coal-gasification facility and later the Company sited various operations functions. Due to the presence of coal tar deposits and Polychlorinated Biphenyl (PCB) contamination and uncertainties as to potential off-site migration of those contaminants, the Company conducted studies in the late 1980's and early 1990's to determine the magnitude and extent of the contamination. After completing its preliminary investigation, the Company engaged a consultant to assist in evaluating clean-up methodologies and provide cost estimates. Those studies indicated the cost to remediate the site would be approximately $5 million. This was charged to expense in the fourth quarter of 1992. Site investigation continued over the next several years. In January of 1995, the Company was formally contacted by the EPA asking for written consent to conduct a site evaluation of the Cleveland Avenue property. That evaluation has been completed. The Company does not believe the EPA's evaluation changes its potential liability so long as the State remains satisfied that reasonable progress continues to be made in remediating the site and retains oversight of the process. In 1995, as part of that process, the Company's consultant completed its risk assessment report and submitted it to the State of Vermont for review. The State generally agreed with that assessment but expressed a number of concerns and directed the Company to collect some additional data. The Company has addressed almost all of the concerns expressed by the State and continues to work with the State in a joint effort to develop a mutually acceptable solution. The Company selected a consulting/engineering firm to collect the additional data requested by the State and develop and implement a remediation plan for the site. That firm has begun work at the site. It has collected the additional data requested by the State and will use all the data gathered to date to formulate a comprehensive remediation plan. The additional data gathered to date has not caused the Company to alter its original estimate of the likely cost of remediating the site. PCB, INC. In August 1995, the Company received an Information Request from the EPA pursuant to a Superfund investigation of two related sites, one in Kansas and the other in Missouri (the Sites). During the mid-1980's, these Sites received materials containing PCBs from hundreds of sources, including the Company. According to the EPA, more than 1,200 parties have been identified as Potential Responsible Parties (PRPs). The Company has complied with the information request and will monitor EPA activities at the Sites. In December 1996, the Company received an invitation to join a PRP steering committee. The Company has not yet decided whether joining that committee would be in its best interest. That committee has estimated the Company's pro rata share of the waste sent to the Sites to be .42%. The committee estimates that the Sites' remediation will cost between $5 million and $40 million. Based on this information, the Company does not believe that the Sites represent the potential for a material adverse effect on its financial condition or results of operations. The Company also faces potential liability arising from the alleged disposal of hazardous materials at two former municipal landfills: the Parker Landfill and the Trafton-Hoisington Landfill. PARKER AND TRAFTON-HOISINGTON LANDFILLS There have been no further developments involving the Company at these sites. The Company's investigations at the time it was originally contacted indicated that it contributed little if any hazardous substances to the sites. The Company has not been contacted by the EPA, the state or any of the PRPs since 1994. Therefore, the Company believes that the likelihood that these sites will cause the Company to accrue significant liability has significantly diminished. For historical information pertaining to these sites, refer to the Company's 1995 Form 10-K. At this time, the Company does not believe these landfill sites represent the potential for a material adverse effect on its financial condition or results of operations but it will continue to monitor activities at the sites. The Company is not subject to any pending or threatened litigation with respect to any other sites that have the potential for causing the Company to incur material remediation expenses, nor has the EPA or other Federal or state agency sought contribution from the Company for the study or remediation of any such sites. In 1996, the Company filed a Federal lawsuit against several insurance companies. In its complaint, the Company alleges that general liability policies issued by the insurers provide coverage for all expenses incurred or to be incurred by the Company in conjunction with, among others, the Cleveland Avenue Property and the Bennington Landfill sites. A settlement has been reached with six of the thirteen defendants. Due to the uncertainties associated with the total outcome of this lawsuit, no receivables have been recorded. Note 3 - Accounts Receivable At September 30, 1997 and December 31, 1996, a total of $12 million of accounts receivable and unbilled revenues were sold under an accounts receivable facility. Accounts receivable and unbilled revenues that have been sold were transferred with limited recourse. A pool of assets, varying between 3% to 5% of the accounts receivable and unbilled revenues sold, are set aside for this potential recourse liability. Accounts receivable and unbilled revenues are reflected net of sales of $6.6 million and $5.4 million, respectively, at September 30, 1997 and $4.8 million and $7.2 million, respectively, at December 31, 1996. Accounts receivable are also reflected net of an allowance for uncollectible accounts of $1.1 million at September 30, 1997 and December 31, 1996. Note 4 - Income Taxes The Company received an accounting order (Order) from the Vermont Public Service Board (PSB) dated September 30, 1997. The Order authorizes the Company to defer and amortize over a 20-year period beginning January 1, 1998, approximately $2.0 million to reflect the revenue requirement level of additional deferred income tax expense resulting from the recently enacted Vermont Corporate income tax increase from 8.25% to 9.75%, subject to a determination that these costs may be recovered in rates in the Company's current rate proceedings. Note 5 - Voluntary Retirement and Severance Programs In the third quarter of 1997, the Company offered voluntary retirement and severance programs to employees. The estimated benefit obligation for the retirement program as of September 30, 1997 is approximately $4.8 million. This amount consists of pension benefits and post-retirement medical benefits of $2.4 million and $2.4 million, respectively. The estimated benefit obligation for the severance program, which includes termination pay as well as other costs, is about $1.8 million. These obligations will be recorded in the fourth quarter of 1997. The Company received an Accounting Order from the PSB dated September 30, 1997, authorizing the Company to defer all of these program costs and amortize them over a five-year period beginning January 1, 1998 through December 31, 2002, subject to a determination that these costs may be recovered in rates in the Company's current rate proceeding. Note 6 - Maine Yankee On August 6, 1997, the Maine Yankee's Board of Directors decided to prematurely retire the Maine Yankee Plant from commercial operation and decommission the facility. The decision to shut down the Plant was based on an economic analysis of the costs of operating it compared to the cost of closing it and incurring replacement power costs over the remaining period of the Plant's operating license. The Plant had been off-line since December 1996. The Company relied on Maine Yankee for less than 5% of its required system capacity. Presently, costs billed to the Company by Maine Yankee, including a provision for ultimate decommissioning of the unit, are being collected from the Company's customers through existing retail and wholesale rate tariffs. Maine Yankee has preliminarily estimated as of September 1, 1997, the sum, in 1997 dollars, of future payments for the closing, decommissioning and recovery of the remaining investment in Maine Yankee to be approximately $929.9 million including a decommissioning obligation of $398.8 million. The Company's total share is approximately $18.6 million of which $3.9 million has been funded through September 30, 1997. This amount is subject to ongoing review and revision and is reflected in the accompanying balance sheet both as regulatory asset and deferred power contract obligation (current and non-current). Note 7 - Investment in Vermont Yankee Nuclear Power Corporation The Company accounts for its investment in Vermont Yankee using the equity method. Abbreviated financial information for Vermont Yankee is as follows (dollars in thousands): Three Months Ended Nine Months Ended September 30 September 30 1997 1996 1997 1996 Operating revenues $41,967 $55,068 $126,771 $138,106 Operating income $ 3,526 $ 3,547 $ 10,816 $ 10,983 Net income $ 1,721 $ 1,735 $ 5,244 $ 5,035 Company's equity in net income $ 548 $ 540 $ 1,649 $ 1,575 CENTRAL VERMONT PUBLIC SERVICE CORPORATION Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS September 30, 1997 Earnings Overview Earnings available for common stock and earnings per share of common stock for the three months ended September 30, 1997 were $1.6 million and $.14, respectively, compared to losses available for common stock of $1.3 million or $.11 per share of common stock during the same period last year. Due to seasonal pricing, the Company normally experiences losses in the second and third quarter when sales are lower and rates are reduced. For the nine months ended September 30, 1997, earnings available for common stock were $13.0 million compared to $12.0 million in 1996. Earnings per share of common stock for these respective periods were $1.13 and $1.04. The improved earnings result primarily from an after tax gain of approximately $1.8 million or $.16 per share of common stock from the sale by Catamount Energy Corporation, a wholly owned non-utility subsidiary of the Company, of its 8.1% partnership's interest in the NW Energy Williams Lake L. P. Project. Other factors affecting results for 1997 are described in Results of Operations below. The Company filed for a 6.6% or $15.4 million general rate increase on September 22, 1997 to become effective June 6, 1998, to offset the increasing cost of providing service as more fully discussed below. RESULTS OF OPERATIONS The major elements of the Consolidated Statement of Income are discussed below. Operating Revenues and MWH Sales A summary of MWH sales and operating revenues for the three and nine months ended September 30, 1997 and 1996 (and the related percentage changes from 1996) is set forth below:
Three Months Ended September 30 Percentage Percentage MWH Increase Revenues (000's) Increase 1997 1996 (Decrease) 1997 1996 (Decrease) Residential 213,402 211,344 1.0 $24,744 $22,053 12.2 Commercial 234,354 229,016 2.3 23,913 21,897 9.2 Industrial 99,945 93,710 6.7 6,997 6,597 6.1 Other retail 1,816 1,842 (1.4) 496 478 3.8 _______ _______ ______ ______ Total retail sales 549,517 535,912 2.5 56,150 51,025 10.0 _______ _______ ______ ______ Resale sales: Firm 258 370 (30.3) 11 21 47.6 Entitlement 91,983 116,752 (21.2) 4,458 6,826 (34.7) Other 217,214 162,032 34.1 6,018 3,938 52.8 _______ _______ ______ ______ Total resale sales 309,455 279,154 10.9 10,487 10,785 (2.8) _______ _______ ______ ______ Other revenues - - - 1,353 2,023 (33.1) _______ _______ ______ ______ Total sales 858,972 815,066 5.4 $67,990 $63,833 6.5 ======= ======= ======= ======= Nine Months Ended September 30 Percentage Percentage MWH Increase Revenues (000's) Increase 1997 1996 (Decrease) 1997 1996 (Decrease) Residential 705,862 711,815 (.8) $ 85,032 $ 78,253 8.7 Commercial 680,489 669,365 1.7 76,451 70,053 9.1 Industrial 314,501 291,415 7.9 24,805 22,735 9.1 Other retail 5,365 5,448 (1.5) 1,455 1,383 5.2 _________ _________ _______ _______ Total retail sales 1,706,217 1,678,043 1.7 187,743 172,424 8.9 _________ _________ _______ _______ Resale sales: Firm 755 1,166 (35.2) 34 60 (43.3) Entitlement 287,469 386,632 (25.6) 14,025 19,716 (28.9) Other 599,792 547,491 9.6 15,795 13,148 20.1 _________ _________ _______ _______ Total resale sales 888,016 935,289 (5.1) 29,854 32,924 (9.3) _________ _________ _______ _______ Other revenues - - - 4,329 4,121 5.0 _________ _________ _______ _______ Total sales 2,594,233 2,613,332 (.7) $221,926 $209,469 5.9 ========= ========= ======== ========
Retail MWH sales for the third quarter ended September 30, 1997 increased 2.5% reflecting the improving Vermont economy. However, retail revenues increased $5.1 million or 10.0% over last year due to a $4.0 million increase in price resulting from a 2% retail rate increase effective in January 1997 and $1.1 million associated with the 2.5% increase in retail MWH sales. The revenue increase was also impacted by a reduction in the company's seasonal rate differential effective April 1, 1997. The seasonal rate adjustment while increasing off-peak revenues will result in lower peak revenues. For the nine months ended September 30, 1997, retail MWH sales increased 1.7% while retail revenues increased $15.3 million or 8.9% compared to last year. The revenue increase results from a $13.0 million increase in price resulting from a 2-phase retail rate increase effective in June 1996 and January 1997 and $2.3 million associated with the 1.7% increase in retail MWH sales. MWH sales for the residential category decreased .8%, reflecting moderate temperatures during the 1997 winter months. The commercial category MWH sales increased 1.7% while the industrial sector MWH sales increased 7.9% primarily due to increased megawatt-hour requirements for snow making by ski area customers. Primarily due to the scheduled termination of several sales agreements in late 1996, entitlement MWH sales and revenues decreased for the three and nine months ended September 30, 1997 compared to the same periods in 1996. Resale sales and revenues increased for the third quarter due to increased off-system sales, short-term system capacity sales and sales to Nepool. The increase for the nine-month period resulted from increased off-system sales and sales to Nepool partially offset by a decrease in unit and short-term system capacity sales. The decrease in other revenues for the third quarter resulted primarily from higher 1996 transmission revenues related to a transmission interconnection service agreement recorded in the third quarter of 1996. For the nine months ended September 30, 1997, other revenues increased due to an increase in transmission revenues related to various transmission interconnection agreements. 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, 1997 and 1996 are as follows (dollars in thousands):
Three Months Ended September 30 1997 1996 Units Amount Units Amount Purchased and produced: Capacity (MW) 536 $23,703 537 $21,650 Energy (MWH) 862,357 16,411 821,899 15,413 _______ _______ Total purchased power costs 40,114 37,063 Production fuel (MWH) 42,799 518 47,354 485 _______ _______ Total purchased power and production fuel costs 40,632 37,548 Entitlement and other resale sales (MWH) 309,197 10,476 278,784 10,764 _______ _______ Net purchased power and production fuel costs $30,156 $26,784 ======= ======= Nine Months Ended September 30 1997 1996 Units Amount Units Amount Purchased and produced: Capacity (MW) 571 $68,161 519 $62,828 Energy (MWH) 2,567,333 53,254 2,568,318 47,946 _______ _______ Total purchased power costs 121,415 110,774 Production fuel (MWH) 174,855 1,209 224,980 1,259 _______ _______ Total purchased power and production fuel costs 122,624 112,033 Entitlement and other resale sales (MWH) 887,261 29,820 934,123 32,864 _______ _______ Net purchased power and production fuel costs $92,804 $79,169 ======= =======
As a result of higher capacity and energy costs and lower entitlement and other resale revenues, net power costs increased $3.4 million, or 12.6% for the third quarter and $13.6 million, or 17.2% for the nine months ended September 30 1997 compared to the same periods last year. These increases in net power costs resulted mostly from incremental replacement power costs associated with Millstone Unit #3, Connecticut Yankee and Maine Yankee nuclear power plants discussed below and an unscheduled 12-day outage at the Vermont Yankee nuclear power plant. Pursuant to a PSB Accounting Order, during the first half of 1997, the Company reduced energy costs by approximately $5.8 million related to the Hydro-Quebec agreement for which a payment of $5.8 million was received from Hydro-Quebec on June 30, 1997. Entitlement and other resale sales decreased for the 1997 periods for reasons discussed above. The Company owns and operates 20 hydroelectric generating units and two gas turbines and one diesel peaking unit with a combined capability of 73.7 MW. The Company has equity ownership interests in four nuclear generating companies: Vermont Yankee, Maine Yankee, Connecticut Yankee and Yankee Atomic. In addition, the Company maintains joint-ownership interests in Joseph C. McNeil, a 53 MW wood, gas and oil-fired unit; Wyman #4, a 619 MW oil-fired unit; and Millstone Unit #3, an 1154 MW nuclear unit. NUCLEAR MATTERS The Company maintains a 1.7303% joint-ownership interest in the Millstone Unit #3 of the Millstone Nuclear Power Station and owns a 2% equity interest in Connecticut Yankee. These two plants are operated by Northeast Utilities (NU). The Company also owns 2%, 3.5% and 31.3% equity interest in Maine Yankee, Yankee Atomic and Vermont Yankee, respectively. Millstone Unit #3 Millstone Unit #3 (Unit #3) has been out of service since March 30, 1996, due to numerous technical and non-technical problems and is on the Nuclear Regulatory Commission's (NRC) watch list. NU is currently implementing comprehensive plans to be "physically ready to restart" by the end of 1997 and the Company is advised that NU anticipates asking the NRC in late January 1998 for permission to restart Unit #3. NU currently estimates that its total 1997 incremental operations and maintenance costs for Unit #3 will be approximately $54.7 million. The Company's share is about $.9 million. In addition, the Company estimates that while Unit #3 is out of service it will incur in 1997 incremental replacement power costs estimated at $1.6 million. These incremental costs are recorded as incurred. The remaining work and inspections of Unit #3 include the Independent Corrective Action Verification Program which began on May 27, 1997, and two major upcoming NRC inspections which must occur prior to restart. For additional information regarding Unit #3, refer to the Company's 1996 Annual Report on Form 10-K. 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 Massachussets 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 Board of Directors decided to prematurely retire the Maine Yankee Plant from commercial operation and decommission the facility. The decision to shut down the Plant was based on an economic analysis of the costs of operating it compared to the cost of closing it and incurring replacement power costs over the remaining period of the Plant's operating license. The Plant has been off-line since December 1996. For additional information regarding the permanent shutdown of the Plant, see Note 6 to the Consolidated Financial Statements in this Form 10-Q. On September 2, 1997, the Maine Public Utilities Commission (MPUC) released a report of a consultant it had retained to perform a management audit of Maine Yankee for the period January 1, 1994 to June 30, 1997. The report concluded that Maine Yankee's decision in December 1996 to proceed with the steps necessary to restart its nuclear generating plant at Wiscasset, Maine (Plant) was "imprudent"; and that Maine Yankee's May 27, 1997 decision to reduce restart expenses while exploring a possible sale of the Plant was "inappropriate." The consultant's report concludes that a more objective and comprehensive competitive analysis at that time "might have indicated a benefit for restarting" the Plant. Those decisions resulted in Maine Yankee incurring $95.9 million in "unreasonable" costs. The Company has charged its 2% share of the Maine Yankee expenses to income. Connecticut Yankee On December 4, 1996, the Board of Directors of Connecticut Yankee decided to prematurely retire the Plant and decommission the facility. The decision was based on an economic analysis of the costs of operating it compared to the costs of closing it and incurring replacement power costs over the remaining period of the plant's operating license. The Company relied on Connecticut Yankee for less than 3% of its required system capacity. Presently, costs billed to the Company by Connecticut Yankee, including a provision for ultimate decommissioning of the unit, are being collected from the Company's customers via existing retail and wholesale rate tariffs. Connecticut Yankee has estimated as of December 31, 1996, the sum of future payments for the closing, decommissioning and recovery of the remaining investment in Connecticut Yankee in 1996 dollars to be approximately $762.8 million subject to ongoing review and revision. The Company's share of remaining costs with respect to Connecticut Yankee's decision to discontinue operation is approximately $13.4 million at September 30, 1997 and is reflected in the accompanying balance sheet both as a regulatory asset and deferred power contract obligation (current and non-current). On June 17, 1997 testimony was filed with the FERC by the Connecticut Department of Public Utility Control and the Connecticut Attorney General's Office in regard to Connecticut Yankee's current decommissioning obligation. Regulators are asking the FERC to prevent the collection of approximately $220 million for the decommissioning of the Connecticut Yankee Nuclear plant. They claim that the current decommissioning costs are excessive and include estimated costs for removal of highly contaminated soil that only became necessary because of "careless and sloppy work habits" by the plant operator. Regulators also argue that the plant closed because its management had been imprudent which led to additional costs that should have been avoided. The Company has denied these allegations. FERC's decision on this matter is pending. Yankee Atomic In 1992, the Board of Directors of Yankee Atomic decided to permanently discontinue operation of their plant, and to decommission the facility. The Company relied on Yankee Atomic for less than 1.5% of its system capacity. Presently, costs billed to the Company by Yankee Atomic, which include a provision for ultimate decommissioning of the unit, are being collected from the Company's customers via existing retail rate tariffs. The Company's share of remaining costs with respect to Yankee Atomic's decision to discontinue operation is approximately $4.7 million at September 30, 1997. This amount is reflected in the accompanying balance sheet both as a regulatory asset and deferred power contract obligation (current and non-current). The Company believes that based on the current regulatory process, its proportionate share of Connecticut Yankee, Yankee Atomic and Maine Yankee 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 financial position, results of operations and cash flows. Although the estimated costs of decommissioning and premature retirements of nuclear power plants are subject to change due to changing technologies and regulations, the Company expects that its liability, including any future change in such costs related to these nuclear power plants will be recovered in its current and future rates. Vermont Yankee The Design Basis Documentation project (Project) initiated by Vermont Yankee during 1996 is expected to be completed by the end of 1999. The Company's 35% share of the total cost for this Project is expected to be about $6.3 million. Such costs will be deferred by Vermont Yankee and amortized over the remaining license life of the plant. Production and Transmission Due to increased production costs, primarily related to Unit #3 and higher transmission costs, production and transmission expenses were $.5 million and $2.1 million higher for the three and nine months ended September 30, 1997 compared to the comparable periods last year. Other Operation Other operating expenses increased $2.8 million for the nine months ended September 30, 1997 principally due to amortization of Conservation and Load Management (C&LM) costs which are recovered in rates. Other Taxes, Principally Property Taxes Due to a property tax refund, other taxes decreased for the third quarter of 1997. Income Taxes Federal and state income taxes fluctuate with the level of pre-tax earnings. The increase in total income tax expense for the three and nine months ended September 30, 1997 results primarily from an increase in pre-tax earnings for the periods and an increase in the Vermont Corporate income tax rate from 8.25% to 9.75% effective January 1, 1997. The Company believes that these additional Vermont Corporate income taxes will be recovered through the regulatory process. The timing and recoverability of these costs will be determined into the company's current rate proceedings. See Note 4 to the consolidated financial statements. Other Income, Net The increase in other income, net for the three months ended September 30, 1997 results principally from a gain on sale of non-utility investment discussed below and higher non-utility subsidiaries' earnings. The increase for the nine months ended September 30, 1997 results primarily from gains on sale of property and investment partially offset by $1.3 million of insurance proceeds recorded in March 1996. Cash Dividends Declared Common The year to date increase in common dividends declared resulted from a 10% increase in the quarterly common dividend paid (from $.20 to $.22 per share) effective for the quarterly common dividend paid on August 15, 1996. LIQUIDITY AND CAPITAL RESOURCES The Company's liquidity is primarily affected by the level of cash generated from operations and the funding requirements of its ongoing construction and C&LM programs. Net cash provided by operating activities was $40.4 million and $42.5 million for the nine months ended September 30, 1997 and 1996, respectively. The Company ended the first nine months of 1997 with cash and cash equivalents of $23.7 million, an increase of $17.4 million from the beginning of the year. The increase in cash for the first nine months of 1997 was the result of $40.4 million provided by operating activities, $7.1 million used for investing activities and $15.9 million used for financing activities. Operating Activities - Net income, depreciation and deferred income taxes and investment tax credits provided $26.7 million. Fluctuations in working capital provided $14.1 million; $4.6 million was provided by deferral/amortization of nuclear refueling replacement energy and maintenance costs, amortization of C&LM costs and other, net; and reduced by $2.1 million and $2.9 million gain from sale of property and investment, respectively. Investing Activities - Construction and plant expenditures consumed $10.7 million, $1.1 million was used for C&LM programs and $1.7 million was used for non-utility investments. Proceeds of $2.6 million and $3.8 million were generated from the sale of property and investment, respectively. Financing Activities - Dividends paid on common stock were $7.6 million, while preferred stock dividends were $1.5 million. Short-term obligations repaid totaled $5.7 million and $1.1 million was used to reacquire common stock. ELECTRIC INDUSTRY RESTRUCTURING The electric utility industry is in a period of transition that may result in a shift away from cost of service and return on equity based rates to one with 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 (Plan), subject to legislative approval, for the Vermont electric utility industry. The Plan, which is a recommendation to the Vermont Legislature, consists of the following nine components: * Provide customer choice. Enable all customers to demand and purchase the products and service they need and want. It provides for additional market opportunities for low-usage customers. * Require Vermont's largest investor-owned utilities to divide their generation and distribution functions into separate corporate subsidiaries. The PSB does not propose full corporate divestiture at this time but requires this "functional separation" of the companies into wholly owned subsidiaries. * Provide for equitable treatment of stranded costs. It promotes aggressive actions to reduce utilities' current and future costs and provides utilities with the opportunity to recover their legitimate, remaining stranded costs. * Address the unique attributes of municipal, cooperative, and small investor-owned utilities. The Plan requires that these utilities provide open access to competitive providers, but does not require functional separation of activities. * Assure consumer protection. Preserves the wide range of consumer protections currently provided by the franchise system. It proposes new initiatives to assist low-income customers. * Deliver cost-effective energy efficiency programs to all customers. It proposes several complimentary approaches to delivering energy efficiency to Vermont's electric consumers. * Promote the continued use and development of renewable energy resources. Requires all retail companies selling electricity in Vermont to secure a minimum percentage of the sales from renewable resources. * Promote national and regional policies that assure environmental quality. The Plan supports proposals in neighboring states to impose environmental comparability on older generation sources and the creation of an inter- regional emissions trading program. * Establish a regional independent system operator (ISO) and power exchange. The Plan proposes the establishment of a regional power exchange to provide a short-term spot market for energy services and other services necessary to support system reliability by the ISO. If adopted by the Vermont Legislature, the Plan would allow for the recovery of stranded costs through a non-bypassable, non-discriminatory wires charge on electric consumption, after mitigation of costs. It would also authorize the use of incentive-and performance-based regulation for distribution companies presently subject to price regulation. The Report promotes aggressive actions to reduce utilities' current and future power costs including "innovative financing renegotiation of above- market contractual commitments, and asset sales." If adopted by the Vermont Legislature, the PSB would take into account the circumstances under which stranded costs were incurred and the companies' efforts to mitigate them. The multiple step process outlined by the PSB would involve 1) an estimation of stranded costs including an estimation of future power costs and a determination of the extent to which stranded costs can be mitigated, 2) an adjustment of stranded costs and 3) a stranded cost reconciliation proceeding. The largest component of the Company's stranded costs are future costs under long-term purchased power contracts. If the PSB's recommendation is approved by the Vermont Legislature, the Company will be able to recover its unmitigatable stranded costs through a non-bypassable, non-discriminatory wires charge on electric consumption. The Report suggests that if utilities satisfy a multi-factor analysis, Vermont should "create the opportunity for full recovery of stranded costs provided they are legitimate, verifiable, otherwise recoverable, prudently incurred and non-mitigatable." Such recovery is, however, "explicitly tied to successful mitigation." At this time, the Company cannot give assurance that it will be successful in realizing mitigation of these costs to the extent that will satisfy the broad standards identified by the PSB or that it will be able to achieve full or substantial recovery of these costs, should Vermont's utility industry be restructured. The PSB Report "strongly encourage[s] the participants in this docket to continue to work together to forge comprehensive solutions on a consensus basis wherever possible." The Company continues to work to achieve a restructured industry in Vermont which meets the consensus principles for industry restructuring endorsed by the PSB and protects the interests of the Company and the stakeholders who financed the system under the regulatory bargain. Due to uncertainty surrounding legislative schedules, the PSB, on April 18, 1997, issued an Order which suspended, pending further legislative action or future PSB Orders, certain filing deadlines for reports and plans to be completed in connection with the Plan. In an effort to achieve a negotiated resolution to the issues surrounding the restructuring of the Vermont electric utility industry, the Company, Green Mountain Power Corporation, the DPS and representatives of the Governor of Vermont developed a Memorandum of Understanding (MOU) in February 1997 establishing a plan for implementing restructuring in Vermont. Although concepts of the MOU are still under consideration, no action has been taken on the MOU. 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 be entitled to purchase electricity in a competitive market place and could choose their electricity supplier. Incumbent investor-owned electric utilities, including the Company, would be required to separate their regulated distribution and transmission operations into affiliate entities that are functionally separate from competitive generation and retail operations. S-62 provides for the recovery of a portion of investor-owned utility's "above market costs" which may be stranded on account of the introduction of competition within their service area. When considering the recovery of such amounts, S-62 would require that the PSB 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. S-62 also creates 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 agrees 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 to be passed by the Vermont House of Representatives in its next session beginning in January 1998 and signed by the Governor of the State of Vermont. At this time, the Vermont House of Representatives is not considering S-62 but instead has convened a special committee of the Vermont House of Representatives to study matters relating to the reform of Vermont's electric utility system with the goal of issuing recommendations prior to the 1998 legislation sessions. The House Committee has for now tabled the idea of competition in the electric utility industry. Therefore, at this time, it cannot be determined whether future restructuring legislation will be enacted in 1998 that would conform to the concepts developed by the Report, the MOU or S-62. New Hampshire In New Hampshire, the New Hampshire Public Utilities Commission (NHPUC), directed by the New Hampshire legislature, has established a Pilot Program (Pilot) to determine the implications of retail competition in the electric utility industry. The Pilot is for a two-year period beginning in May 1996 and is open to all electric utilities and to 3% of all classes of customers in New Hampshire. The Company competed as a competitive supplier to acquire additional load currently served by other New Hampshire utilities and to retain load currently served by Connecticut Valley Electric Company Inc. (Connecticut Valley), the Company's wholly owned New Hampshire subsidiary. The Company acquired new customers with combined annual electric use totaling approximately 20,000 megawatt hours. On February 28, 1997 the NHPUC released its Final Plan to restructure the electric utility industry in New Hampshire pursuant to legislation enacted in New Hampshire during 1996. Concurrently, supplemental utility- specific orders to establish interim stranded cost charges were issued. The legislation requires each utility to file comprehensive plans no later than June 30, 1997, which comply with the Final Plan and the supplemental orders. By a later Order, dated May 22, 1997, the NHPUC modified the scope of the June 30, 1997 filing and only required the filing of open access tariffs for informational purposes. The 1996 legislation also states that utilities shall not be required to implement their compliance filings unless compliance filings representing at least 70% of New Hampshire retail kilowatt hour sales, on an annual basis, have been or are being implemented. The 1997 legislature amended this requirement to the extent that a utility having less than 50% of statewide retail electric distribution sales (measured in kilowatt hours per year) may seek a ruling by the NHPUC that it is in the public interest that implementation of such utility's compliance filing be deferred until compliance filings representing 70% of retail electric sales have been or are being implemented. In its Final Plan, the NHPUC announced a departure from cost-based ratemaking and instead adopted a market-priced approach to stranded cost recovery. The Company believes that if the NHPUC adopted the Final Plan in its present form, Connecticut Valley, as well as, the Company's wholesale power business with Connecticut Valley, would no longer be able to apply Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting For The Effects of Certain Types of Regulation," and the Company may have to remove from its balance sheet substantially all of its regulatory assets associated with New Hampshire business estimated at approximately $3.0 million as of December 31, 1997, on a pre-tax basis. In addition, the supplemental order specific to Connecticut Valley denies stranded cost recovery related to its Federal Energy Regulatory Commission (FERC) approved power contract with the Company and further ordered Connecticut Valley to terminate the contract. The net revenue loss associated with costs potentially disallowed under the power contract are estimated by the Company to total over $80.0 million (pre-tax) over a twenty-eight year period on a nominal dollar basis. The Company intends to vigorously pursue the recovery of these costs and will continue to assess the likelihood of recovery. If it is determined that it is probable that FERC will not permit recovery of these costs, the Company would have to assess the likelihood and magnitude of losses incurred under both SFAS No. 5, "Accounting for Contingencies" and SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and for Long Lived Assets to be Disposed Of." On April 7, 1997, the NHPUC issued an Order addressing certain threshold procedural matters raised in the motion for rehearing and/or clarification filed by various parties, including Connecticut Valley, relative to the Final Plan and interim stranded cost orders. The Order suspends and stays those aspects of the Final Plan that are the subject of rehearing or clarification requests in order to thoroughly review and evaluate the issues raised in such motions and also suspends and stays the interim stranded cost orders for the various parties, including Connecticut Valley. The suspension and stay of these orders will remain in effect until two weeks following the issuance of any order concerning outstanding requests for rehearing and clarification. On May 9, 1997, Public Service Company of New Hampshire (PSNH) filed a Motion For Suspension of the electric utility restructuring proceeding to allow mediation with the State of New Hampshire to proceed. On May 22, 1997, NHPUC issued an Order granting PSNH's Motion For Suspension until July 2, 1997. On July 2, 1997, PSNH filed another Motion For Continued Suspension of the proceedings. On July 21, 1997, NHPUC issued an Order extending the suspension of the rehearing schedule until August 5, 1997. On August 1, 1997, PSNH filed another Motion For Continued Suspension of the proceedings. On August 12, 1997, the NHPUC issued Order No. 22,681 denying PSNH's Motion For Suspension and establishing a schedule of rehearing of PSNH specific issues regarding rate-making and the Rate Agreement. The NHPUC adopted a procedural schedule to rehear these PSNH specific issues so as not to interfere with the ongoing mediation which continued until September 2, 1997. The Final Plan and supplemental order also contain rulings on numerous issues that may have a substantial effect on the operations of the Company. Included among these rulings is the requirement that Connecticut Valley divest within two years all of its wholesale power purchase contracts; a prohibition on the remaining distribution company and its affiliates from engaging in retail marketing or load aggregation services; and a mandate for the filing of tariffs with the FERC for the provision of unbundled retail transmission service. Connecticut Valley's utility specific supplemental order did approve the recovery through interim stranded cost charges of the projected above market power costs associated with purchases from Qualifying Facilities that were previously approved by the NHPUC. PSNH and various PSNH affiliates, including Northeast Utilities, have filed an action for injunctive and declaratory relief in the New Hampshire Federal District Court (Court) with respect to the NHPUC's Final Plan and the supplemental order pertaining to PSNH. The Court has rendered, and later amended, a temporary restraining order in favor of PSNH. The Court has also rendered an order declining to abstain, except, at present, with respect to certain limited issues regarding ratemaking and regarding a Rate Agreement between PSNH and the State of New Hampshire. The Company and Connecticut Valley have filed claims for intervention (seeking declaratory relief with respect to the NHPUC's Final Plan and pertinent supplemental order) and have moved to intervene in PSNH's federal action. Intervention status was granted to the Company and Connecticut Valley by the Federal Court. On September 2, 1997, the mediator appointed by the Court to mediate PSNH's claims reported that the mediation effort had failed. PSNH was the only New Hampshire utility involved in that attempt to resolve the dispute. On September 15, 1997 the US District Court of Rhode Island reported that it no longer had jurisdiction over the matter because the Circuit Court of Appeals had docketed several appeals to District Court's earlier orders. The Circuit Court of Appeals has scheduled a hearing on December 5, 1997. Those appeals pertain to motions for intervention status previously denied to non-utility parties the standards for granting injunctive relief and the jurisdiction of the court over the matters. On September 29, 1997, a Legal and Policy Memorandum was filed by the New Hampshire Governor with the NHPUC that had as its stated purpose "...to moot the federal case and bring the restructuring effort back to New Hampshire, where it belongs." Among other things, the Governor proposed the NHPUC abandon its proposed benchmark approach to ratemaking and return to a cost-based, ratemaking method. The Governor and other parties have proposed numerous cost-based methodologies. The NHPUC has scheduled hearings from November 20 through November 26, 1997 for the PSNH rehearing issues. Other rehearing issues will be addressed subsequently. As stated above, the NHPUC in its supplemental order specific to Connecticut Valley denies stranded cost recovery related to its FERC approved power contract with the Company and further ordered Connecticut Valley to terminate the contract. However, FERC, in its Order No. 888, established that it would determine stranded cost recovery and make such recoveries a component of charges for transmission service in cases of wholesale termination. Accordingly, on June 25, 1997, the Company petitioned the FERC to assert its jurisdiction over the recovery of stranded costs resulting from the NHPUC's Final Plan and allow recovery rejected by the New Hampshire Regulators. Various interests have sought party status before the FERC in this matter. A notice scheduling a pre-hearing conference by the FERC has not yet been scheduled. The Company has initiated and will continue to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC. The Company cannot predict whether the ultimate outcome of this matter 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, "Accounting for the Effects of Certain Types of Regulation," requires regulated entities, in appropriate circumstances, to establish regulatory assets and liabilities, and thereby defer the income statement impact of certain costs and revenues that are expected to be realized in future rates. As described in Note 1 of Notes to Consolidated Financial Statements, included in the Company's 1996 Annual Report on Form 10-K, the Company complies with the provisions of SFAS No. 71. In the event the Company determines that it no longer meets the criteria for following SFAS No. 71, the accounting impact would be an extraordinary, non-cash charge to operations of an amount that could be material. Criteria that give rise to the discontinuance of SFAS No. 71 include (1) increasing competition that restricts the Company's ability to establish prices to recover specific costs and (2) a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. The Securities and Exchange Commission has questioned the ability of certain utility companies continuing the application of SFAS No. 71 where legislation provided for the transition to retail competition. The issue of 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 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. The Company's Management believes that SFAS No. 71 continues to apply to its regulated operations. SFAS No. 121, "Accounting for the Impairment of Long Lived Assets and for Long-Lived Assets to Be Disposed Of," which was implemented by the Company on January 1, 1996, requires that any assets, including regulatory assets, that are no longer probable of recovery through future revenues, be revalued based upon future cash flows. SFAS No. 121 requires that a rate- regulated enterprise recognize an impairment loss for the amount of costs excluded from recovery. As of September 30, 1997, based upon the regulatory environment within which the Company currently operates, SFAS No. 121 did not have an impact on the Company's financial position or results of operations. Competitive influences or regulatory developments may impact this status in the future. The Company believes that the provisions of both the Report and MOU, if ultimately approved by the PSB and Vermont General Assembly, would meet the criteria for continuing application of SFAS Nos. 71 and 121. Conversely, the Company believes that the unmodified provisions of S-62 and the NHPUC Final Plan would not meet the criteria for continuing application of SFAS No. 71 and 121. Because the Company is unable to predict what form possible future 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 under S-62 or the NHPUC Final Plan, the Company would have to assess the likelihood and magnitude of losses incurred under SFAS No. 5. As such, the Company cannot predict whether the Report, the MOU and restructuring legislation enacted in Vermont or the issuance of a final restructuring Plan in New Hampshire would have a material adverse effect on the Company's operations, financial condition or credit ratings. However, the Company's failure to recover a significant portion of its purchased power costs, would likely have a material adverse effect on the Company's results of operations, cash flows and ability to obtain capital at competitive rates. It is possible that stranded cost exposure, including the potential impact of write-offs associated with SFAS Nos. 5, 71, and 121, before mitigation could exceed the Company's current total common stock equity. FINANCING AND CAPITALIZATION Utility The level of short-term borrowings fluctuates based on seasonal corporate needs, the timing of long-term financings and market conditions. Short-term borrowings are supported by committed and uncommitted lines of credit with several banks totaling $36.0 million. On November 7, 1997, the Company implemented a 364 day Revolving Credit and Competitive Advance Facility (Credit Facility) providing for up to $50 million of Credit Facility which upon PSB regulatory approval will become a Three Year Revolving Credit Facility. This Credit Facility will be used for general corporate purposes and to replace $36 million of the committed and uncommitted lines of credit. The Company's capital structure ratios as of September 30, 1997 (including amounts of long-term debt and preferred stock due within one year), consisted of 53.5% common equity, 7.9% preferred stock and 38.6% long-term debt including capital lease obligations. At September 30, 1997, the Company's mandatory sinking fund requirements for long-term debt and preferred stock due within the next twelve-month period is approximately $3.0 million and $1.0 million, respectively. Current credit ratings for the Company's outstanding mortgage debt, Standard & Poor's corporate credit rating and preferred stock are as follows: Duff & Standard Phelps & Poor's First Mortgage Bonds BBB A- Corporate Credit Rating BBB Preferred Stock BBB- BBB- Non-Utility Catamount Energy Corporation (Catamount), a wholly owned subsidiary of the Company, implemented a credit facility in July 1996 which provides for up to $8 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. SmartEnergy, also a wholly owned subsidiary of the Company, currently maintains $.5 million revolving line of credit with a bank to provide working capital and financing assistance for investment purposes. There are no outstanding borrowings under this facility. Financial obligations of the Company's non-utility wholly owned subsidiaries are non-recourse to the Company. C&LM Programs The primary purpose of these programs is to offset the need for long- term power supply and delivery resources that are more expensive to purchase or develop than customer-efficiency programs. Total C&LM expenditures in 1996 were $3.5 million, and based on an agreement between the Company and the DPS and approved by the PSB, total 1997 C&LM expenditures are not to exceed $4.5 million. Diversification Catamount was formed for the purpose of investing in non-regulated power plant projects. Currently, Catamount, through its wholly owned subsidiaries, has interests in five operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont and Hopewell, Virginia. In addition, Catamount has interests in projects under construction in Thetford, England, and under development in Summersville, West Virginia. Catamount's net income was $2.6 million and $3.6 million for the three and nine months ended September 30, 1997. For the three and nine months ended September 30, 1996, Catamount incurred a net loss of $114,000 and net income of $144,000, respectively. Included in results of operation for the nine months ended September 30, 1997 and 1996 were $.4 million and $1.8 million, respectively, of pre-tax costs related to the Gauley River project in Summersville, West Virginia. These expenses would be reimbursed and taken into income if this pending project reaches financial closing. On August 5, 1997, Catamount sold its 8.1% partnership's interest in the NW Energy Williams Lake L.P. project. The sale resulted in a $1.8 million after-tax gain or approximately $.16 per share of common stock during the third quarter of 1997. For the three and nine months ended September 30, 1997, SmartEnergy incurred a net loss of $202,000 and $164,000, respectively compared to earnings of $84,000 and $271,000 for the three and nine months ended September 30, 1996. RATES AND REGULATION The Company recognizes adequate and timely rate relief is necessary if the Company is to maintain its financial strength, particularly since Vermont regulatory rules do not allow for changes in purchased power and fuel costs to be passed on to consumers through automatic rate adjustment clauses. The Company's practice of reviewing costs periodically will continue and rate increases will be requested when warranted. The Company filed for a 6.6% or $15.4 million general rate increase on September 22, 1997 to become effective June 6, 1998 to offset increasing cost of providing service. Approximately $14.3 million or 92.9% of the rate increase request is to recover 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. During proceedings related to the April 30, 1996 Order described in the Company's 1996 Annual Report on Form 10-K, certain intervening parties petitioned the PSB for a management audit of the Company. In an Order dated April 10, 1996, the PSB severed the management audit issue from the rate proceeding. The PSB held a status conference on May 6, 1996 to address whether there should be such an audit as well as other related issues. Hearings for the management audit issue were held on July 16, 1996 and August 29, 1996. On April 17, 1997, the PSB issued an Order which rejects the idea of a traditional management audit of the Company and instead 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 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. NEW ACCOUNTING PRONOUNCEMENTS In June 1996, the FASB issued SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," effective for transfers and servicing of financial assets and extinguishments of liabilities occuring after December 31, 1996. Earlier or retroactive application is not permitted. Subsequently, in December 1996, the FASB issued SFAS No. 127, "Deferral of the Effective Date of Certain Provisions of SFAS No. 125." This statement defers for one year the effective date of certain provisions of SFAS No. 125. The Company anticipates that the adoption of SFAS No. 125 will not have a material impact on the Company's financial position or results of operations. In February 1997, the Financial Accounting Standards Board issued SFAS No. 128, "Earnings per Share," effective for both interim and annual periods ending after December 15, 1997. Earlier application is not permitted. SFAS No. 128 establishes standards for computing and presenting earnings per share(EPS) and applies to entities with publicly held common stock or potential common stock. The Company anticipates that the adoption of SFAS No. 128 will not have an impact on the Company's computation and presentation of basic EPS. The Company does not have any potential common stock that would result in the dilution of EPS. YEAR-2000 COMPLIANCY The Company is in process of assessing the scope, magnitude and costs of making its computer systems and applications year-2000 compliant. The assessment is expected to be completed by the end of the fourth quarter of 1997. Although final costs cannot be determined at this time, the Company does not believe that these costs represent the potential for a material adverse effect on its financial position or results of operations. FORWARD LOOKING STATEMENTS Statements in this report relating to future financial conditions are forward looking statements. Such forward-looking statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors, which may cause the actual results, performance or achievements to differ materially from the future forward- looking statements. Such factors include general economic and business conditions, changes in industry regulation, weather and other factors which are described in further detail in the Company's filings with the Securities and Exchange Commission. CENTRAL VERMONT PUBLIC SERVICE CORPORATION PART II - OTHER INFORMATION Item 1. Legal Proceedings. On July 29, 1996, the Company filed a Declaratory Judgment action pertaining to remediation in the United States District Court for the District of Vermont. The Complaint names as defendants a number of insurance companies that issued insurance policies to the Company dating from the mid 1940s to the late 1980s. The Company asserts that insurance policies issued by defendants provide coverage for all defense and remediation costs associated with the Cleveland Avenue property, the Bennington Landfill site and the North Clarendon site. With the exception of the North Clarendon site where no further remediation is anticipated, see Note 2 to the Consolidated Financial Statements for related disclosures. Items 2, 3, and 4. None. Item 5. Other Information (a) Frederic H. Bertrand was elected Chairman of the Board of Directors on September 2, 1997 to replace F. Ray Keyser Jr., who retired as Chairman at the end of September 1997 and plans to retire as Director on December 31, 1997 (b) On June 27, 1997, NU's management temporarily suspended all nucleartraining programs at Millstone to address programmatic deficiencies identified by NU's subsidiary, Northeast Nuclear Energy Company and the NRC inspectors during reviews of NU system's licensed operator training programs at NU system's four Connecticut nuclear units. Currently, Training Restart Plan has been established and various training programs have been restarted including the licensed operator training programs for Millstone. NU's management continues to believe that the suspension will not affect the current schedule to restart Unit #3. Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits. EXHIBIT INDEX 27. Financial Data Schedule. (b) There were no reports on Form 8-K for the quarter ended September 30, 1997. 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, Finance and Administration and Principal Financial Officer By James M. Pennington ___________________________________________ James M. Pennington, Vice President, Controller and Principal Accounting Officer Dated November 13, 1997 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-31-1997 SEP-30-1997 PER-BOOK 323,025 59,884 56,791 71,898 0 511,598 65,987 45,290 79,562 190,839 19,000 8,054 117,374 0 0 0 3,001 1,000 17,493 1,094 153,743 511,598 221,926 6,375 201,118 207,493 14,433 7,370 21,803 7,274 14,529 1,521 13,008 7,583 6,030 40,407 1.13 0
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