-----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, RcF/NAnqJ0wQHArmHTWVUj1iovnq9GHJ9/mIetImJ3XdLeOVAEhmrPiQE26ZAjdY S7/Q+UknOuOXAfZg9Hw/qQ== 0000018808-98-000051.txt : 19980812 0000018808-98-000051.hdr.sgml : 19980812 ACCESSION NUMBER: 0000018808-98-000051 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19980630 FILED AS OF DATE: 19980807 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: 98679313 BUSINESS ADDRESS: STREET 1: 77 GROVE ST CITY: RUTLAND STATE: VT ZIP: 05701 BUSINESS PHONE: 8027732711 10-Q 1 FORM 10-Q PERIOD ENDING 6/30/98 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 June 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 July 31, 1998 there were outstanding 11,442,376 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 six months ended June 30, 1998 and 1997 3 Consolidated Balance Sheet as of June 30, 1998 and December 31, 1997 4 Consolidated Statement of Cash Flows for the six months ended June 30, 1998 and 1997 5 Notes to Consolidated Financial Statements 6-11 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 12-27 PART II. OTHER INFORMATION 28-29 SIGNATURE 30 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 Six Months Ended June 30 June 30 1998 1997 1998 1997 ---- ---- ---- ---- Operating Revenues $66,406 $65,442 $150,364 $153,936 Operating Expenses Operation Purchased power 45,882 40,305 85,588 81,301 Production and transmission 5,766 5,610 11,354 11,287 Other operation 11,419 10,698 22,853 20,683 Maintenance 3,802 3,685 7,654 6,726 Depreciation 4,231 4,229 8,458 8,689 Other taxes, principally property taxes 2,804 2,718 5,844 5,706 Taxes on income (3,419) (918) 2,013 6,289 ------- ------- -------- -------- Total operating expenses 70,485 66,327 143,764 140,681 ------- ------- -------- -------- Operating Income (Loss) (4,079) (885) 6,600 13,255 ------- ------- -------- -------- Other Income and Deductions Equity in earnings of affiliates 844 792 1,576 1,677 Allowance for equity funds during construction 11 24 28 44 Other income, net 354 1,012 932 3,756 Benefit (provision) for income taxes 52 (149) 62 (1,031) ------- ------- -------- -------- Total other income and deductions, net 1,261 1,679 2,598 4,446 ------- ------- -------- -------- Total Operating and Other Income (Loss) (2,818) 794 9,198 17,701 Net Interest Expense 2,634 2,649 5,259 5,237 ------- ------- -------- -------- Net Income (Loss) Before Extraordinary Credit (5,452) (1,855) 3,939 12,464 Extraordinary Credit Net of Taxes - - 873 - ------- ------- -------- -------- Net Income (Loss) (5,452) (1,855) 4,812 12,464 Retained Earnings at Beginning of Period 85,613 85,415 75,841 74,137 ------- ------- -------- -------- 80,161 83,560 80,653 86,601 Cash Dividends Declared Preferred stock 487 507 973 1,014 Common stock 5,028 5,070 5,034 7,604 ------- ------- -------- -------- Total dividends declared 5,515 5,577 6,007 8,618 ------- ------- -------- -------- Retained Earnings at End of Period $74,646 $77,983 $ 74,646 $ 77,983 ======= ======= ======== ======== Earnings (Losses) Available For Common Stock $(5,939) $(2,362) $ 3,839 $ 11,450 Average Shares of Common Stock Outstanding 11,425,725 11,469,837 11,424,843 11,494,655 Basic and Diluted Share of Common Stock: Earnings (losses) before extraordinary credit $(.52) $(.21) $.26 $1.00 Extraordinary credit - - .08 - ----- ----- ---- ----- Earnings (Losses) Per Basic and Diluted Share of Common Stock $(.52) $(.21) $.34 $1.00 ===== ===== ==== ===== Dividends Paid Per Share of Common Stock $.22 $.22 $.44 $.44 The accompanying notes are an integral part of these consolidated financial statements. CENTRAL VERMONT PUBLIC SERVICE CORPORATION CONSOLIDATED BALANCE SHEET (Dollars in thousands) June 30 December 31 1998 1997 ---- ---- Assets Utility Plant, at original cost $462,512 $461,482 Less accumulated depreciation 158,873 151,250 -------- -------- 303,639 310,232 Construction work in progress 15,067 10,450 Nuclear fuel, net 947 964 -------- -------- Net utility plant 319,653 321,646 -------- -------- Investments and Other Assets Investments in affiliates, at equity 26,121 26,495 Non-utility investments 35,256 33,736 Non-utility property, less accumulated depreciation 2,787 2,894 -------- -------- Total investments and other assets 64,164 63,125 -------- -------- Current Assets Cash and cash equivalents 8,777 16,506 Special deposits 340 404 Accounts receivable, less allowance for uncollectible accounts ($1,961 in 1998 and $1,946 in 1997) 21,196 23,166 Unbilled revenues 12,369 18,951 Materials and supplies, at average cost 3,868 3,779 Prepayments 1,485 1,464 Other current assets 5,395 4,970 -------- -------- Total current assets 53,430 69,240 -------- -------- Regulatory Assets 73,343 73,209 -------- -------- Other Deferred Charges 4,960 4,720 -------- -------- Total Assets $515,550 $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 45,307 45,295 Treasury stock (353,447 shares and 362,447 shares, respectively, at cost) (4,610) (4,728) Retained earnings 74,646 75,841 -------- -------- Total common stock equity 186,058 187,123 Preferred and preference stock 8,054 8,054 Preferred stock with sinking fund requirements 18,000 19,000 Long-term debt 108,839 93,099 Long-term lease arrangements 16,682 17,223 -------- -------- Total capitalization 337,633 324,499 -------- -------- Current Liabilities Short-term debt 250 12,650 Current portion of long-term debt and preferred stock 21,521 24,271 Accounts payable 5,643 4,609 Accounts payable - affiliates 11,412 12,441 Accrued income taxes (3,721) 6,631 Dividends declared 3,000 2,513 Nuclear decommissioning costs 6,010 6,010 Other current liabilities 16,021 21,646 -------- -------- Total current liabilities 60,136 90,771 -------- -------- Deferred Credits Deferred income taxes 56,780 53,996 Deferred investment tax credits 7,026 7,222 Nuclear decommissioning costs 26,020 28,947 Other deferred credits 27,955 26,505 -------- -------- Total deferred credits 117,781 116,670 -------- -------- Total Capitalization and Liabilities $515,550 $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) Six Months Ended June 30 1998 1997 ---- ---- Cash Flows Provided (Used) By Operating Activities Net income $ 4,812 $12,464 Adjustments to reconcile net income to net cash provided by operating activities Equity in earnings of affiliates (1,576) (1,677) Dividends received from affiliates 1,312 1,605 Equity in earnings of non-utility investments (3,046) (2,491) Distribution of earnings from non-utility investments 1,663 2,209 Extraordinary credit (1,294) - Depreciation 8,458 8,689 Deferred income taxes and investment tax credits 2,928 (286) Allowance for equity funds during construction (28) (44) Net deferral and amortization of nuclear refueling replacement energy and maintenance costs (4,168) 2,781 Amortization of conservation and load management costs 3,509 3,509 Gain on sale of property - (2,095) Decrease in accounts receivable and unbilled revenues 9,560 13,236 Increase (decrease) in accounts payable 315 (1,496) Increase (decrease) in accrued income taxes (10,352) 494 Change in other working capital items (6,394) 2,901 Other, net 698 (1,337) ------- ------- Net cash provided by operating activities 6,397 38,462 ------- ------- Investing Activities Construction and plant expenditures (6,935) (6,922) Deferred conservation & load management expenditures (1,195) (806) Return of capital 93 93 Proceeds from sale of property - 2,624 Non-utility investments (100) (776) Other investments, net (178) 137 ------- ------- Net cash used for investing activities (8,315) (5,650) ------- ------- Financing Activities Sale (repurchase) of common stock 112 (1,072) Short-term debt, net (400) (5,760) Long-term debt, net (10) - Common and preferred dividends paid (5,513) (6,082) ------- ------- Net cash used for financing activities (5,811) (12,914) ------- ------- Net Increase (Decrease) in Cash and Cash Equivalents (7,729) 19,898 Cash and Cash Equivalents at Beginning of Period 16,506 6,365 ------- ------- Cash and Cash Equivalents at End of Period $ 8,777 $26,263 ======= ======= Supplemental Cash Flow Information Cash paid during the period for: Interest (net of amounts capitalized) $ 5,106 $ 4,748 Income taxes (net of refunds) $ 9,777 $ 7,164 The accompanying notes are an integral part of these consolidated financial statements. CENTRAL VERMONT PUBLIC SERVICE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 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 One such site is the Company's Cleveland Avenue property located in the City of Rutland, Vermont, a site where one of its predecessors operated a coal-gasification facility and later the Company sited various operations functions. Due to the presence of coal tar deposits and Polychlorinated Biphenyl (PCB) contamination and uncertainties as to potential off-site migration of those contaminants, the Company conducted studies in the late 1980's and early 1990's to determine the magnitude and extent of the contamination. After completing its preliminary investigation, the Company engaged a consultant to assist in evaluating clean-up methodologies and provide cost estimates. Those studies indicated the cost to remediate the site would be approximately $5 million. This was charged to expense in the fourth quarter of 1992. Site investigation continued over the next several years. In January of 1995, the Company was formally contacted by the EPA asking for written consent to conduct a site evaluation of the Cleveland Avenue property. That evaluation has been completed. The Company does not believe the EPA's evaluation changes its potential liability so long as the State remains satisfied that reasonable progress continues to be made in remediating the site and retains oversight of the process. In 1995, as part of that process, the Company's consultant completed its risk assessment report and submitted it to the State of Vermont for review. The State generally agreed with that assessment but expressed a number of concerns and directed the Company to collect some additional data. The Company has addressed almost all of the concerns expressed by the State and continues to work with the State in a joint effort to develop a mutually acceptable solution. The Company selected a consulting/engineering firm to collect the additional data requested by the State and develop and implement a remediation plan for the site. That firm has begun work at the site. It has collected the additional data requested by the State and will use all the data gathered to date to formulate a comprehensive remediation plan. The additional data gathered to date has not caused the Company to alter its original estimate of the likely cost of remediating the site. PCB, INC. AND OSAGE METALS In August 1995, the Company received an Information Request from the EPA pursuant to a Superfund investigation of 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 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 has been identified as a PRP at a third related site to which PCB Treatment, Inc. shipped capacitors for disposal, Osage Metals. The EPA has concluded that the Company is a De Minimus party at this Site and has offered to settle with the Company on this basis. The Company has accepted the EPA's offer. That settlement, under which the Company pays the EPA about $3,600, will be finalized in the next 60 days. 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 alleges that general liability policies issued by the insurers provide coverage for all expenses incurred or to be incurred by the Company in conjunction with, among others, the Cleveland Avenue Property. Settlements have been reached with all but one defendant, with whom the Company has reached a settlement in principle. Due to the uncertainties associated with the outcome of this lawsuit related to the remaining defendant and the actual clean-up costs, the proceeds have been applied to the environmental reserve. Note 3 - Retail Rates Vermont: The Company's practice of reviewing costs periodically will continue and rate increases will be requested when warranted. The Company filed for a 6.6%, or $15.4 million 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 (VJO) claiming that the decision of the Company to commit to the power contract in 1991 was imprudent and that power now purchased pursuant to that agreement is not "used and useful." The parties have also claimed that the Company has not met a condition of the Vermont Public Service Board's (PSB) prior approval of the contract, requiring that the Company obtain all cost effective Demand Side Management. In response, the Company filed a motion asking the PSB to rule that any prudence and used and useful issues were resolved in prior proceedings and that the PSB is precluded from again trying the Company on those issues. On April 17, 1998, the PSB issued an order generally denying the Company's motion. Given the fact that the PSB had recently severely penalized another VJO member, Green Mountain Power Corporation, in an Order dated February 27, 1998, after finding that its decision to lock-in the Hydro-Quebec contract was imprudent and the power purchased pursuant to that lock-in was not used and useful, the Company concluded that it was necessary to have the so-called preclusion issue reviewed by the Vermont Supreme Court (VSC) before the PSB issues a final order in the Company's current rate case. As such, the Company and other parties 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 delay the date that new rates would have otherwise taken effect which could now be as late as early-1999. As a result, the Company's earnings prospects for all of 1998 will continue to 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 percent rate increase request referenced above. New Hampshire: On November 26, 1997, Connecticut Valley filed a request with the New Hampshire Public Utilities Commission (NHPUC) to increase the Fuel Adjustment Clause (FAC), Purchased Power Cost Adjustment (PPCA) and short-term energy purchase rates effective on or after January 1, 1998. The requested increase in rates results from higher forecast energy and capacity charges on power Connecticut Valley purchases from the Company plus removal of a credit effective during 1997 to refund overcollections from 1996. In an Order dated December 31, 1997, the NHPUC directed Connecticut Valley to freeze its current FAC and PPCA rates (other than short-term rates to be paid to certain Qualifying Facilities) effective January 1, 1998, on a temporary basis pending a hearing to determine: 1) the appropriate proxy for a market price that Connecticut Valley could have obtained if it had terminated its wholesale contract with the Company; 2) the implications of allowing Connecticut Valley to pass on to its customers only that market price; and 3) whether the NHPUC's final determination on the FAC and PPCA rates should be reconciled back to January 1, 1998 or some other date. On January 19, 1998, Connecticut Valley and the Company (Companies) filed with the Court for a temporary restraining order to maintain the status quo ante by staying the NHPUC Order of December 31, 1997 and preventing the NHPUC from taking any action that (i) compromises cost-based rate making for Connecticut Valley; (ii) interferes with the Federal Energy Regulatory Commission's (FERC) exclusive jurisdiction over the Company's pending application to recover wholesale stranded costs upon termination of its wholesale power contract with Connecticut Valley; or (iii) prevents Connecticut Valley from recovering through retail rates the stranded costs and purchased power costs that it incurs pursuant to its FERC-authorized wholesale rate schedule with the Company. On February 23, 1998, the NHPUC announced in a public meeting that it reaffirmed its finding of imprudence and would designate a proxy market price for power at 4 cents per kWh in lieu of the actual costs incurred pursuant to the wholesale power contract with the Company. In addition, the NHPUC indicated, subject to certain conditions 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 addresses all outstanding motions for rehearings or clarification relative to the policies or legal positions articulated in the Final Plan and removes the stay covering the Company's interim stranded cost order of April 7, 1997. In addition, the March 20, 1998 Order imposed various compliance filing requirements. On April 3, 1998, the Court held a hearing on the Companies' motion for a Temporary Restraining Order (TRO) and Preliminary Injunction against the NHPUC at which time both the Companies and the NHPUC presented arguments. In an oral ruling 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. Also, on April 3, 1998, the Court indicated its TRO enjoining the NHPUC's restructuring orders applied to Connecticut Valley and prohibits the enforcement of the restructuring orders until the Court conducts a consolidated hearing and rules on the requests for permanent injunctive relief by plaintiff Public Service Company of New Hampshire (PSNH) and the other utilities that have been allowed to intervene in these proceedings, including the Company and Connecticut Valley. The plaintiffs-intervenors 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 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 the November hearing. The Company believes that the Court will convert the preliminary injunction to a permanent injunction. As a result of these Court orders, Connecticut Valley's 1997 charges under SFAS No. 5 and SFAS No. 71, described above, were reversed in the first quarter of 1998. Combined, the reversal of these charges increased first quarter 1998 net income and earnings per share of common stock by approximately $4.5 million and $.39, respectively. On April 1, 1998, Citizens Bank of New Hampshire (Bank) notified Connecticut Valley that it was in default of the Loan Agreement between the Bank and Connecticut Valley dated December 27, 1994 and that the Bank will exercise all of its remedies from and after May 5, 1998 in the event that the violations are not cured. After reversing the 1997 write-offs described above, Connecticut Valley 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 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. On June 25, 1997, the Company filed with the FERC a notice of termination of its power supply contract with Connecticut Valley, conditional upon the Company's request to impose a surcharge on the Company's transmission tariff to recover the stranded costs that would result from the termination of its contract with Connecticut Valley. The amount requested was $44.9 million plus interest at the prime rate to be recovered over a ten-year period. In its Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected the Company's proposed stranded cost surcharge mechanism but indicated that it would consider an exit fee mechanism for collecting stranded costs. The FERC also rejected the Company's arguments concerning the applicability of stated FERC policies regarding retail stranded costs, multi-state regulatory gaps and the implications of state restructuring initiatives. The Company has filed a motion seeking rehearing of the FERC's December 18, 1997 Order. In addition, and in accordance with the December 18, 1997 FERC Order, on January 12, 1998 the Company filed a request with the FERC for an exit fee mechanism to collect $44.9 million in a lump sum, or in installments with interest at the prime rate over a ten-year period, to cover the stranded costs resulting from the cancellation of Connecticut Valley's power contract with the Company. On March 11, 1998, the FERC issued an order accepting for filing the Company's request for an exit fee effective March 14, 1998, and set hearings to determine: whether Connecticut Valley will become an unbundled transmission customer of the Company, the Company's expectation as to the period of time it would serve Connecticut Valley, and the allowable amount of the exit fee. The FERC also rejected the Company's June 25, 1997 notice of termination indicating that the notice can be resubmitted when the power contract is proposed to be terminated. On April 28, 1998, the Company filed its case-in-chief before the FERC updating the amount of the exit fee to $54.9 million in a lump sum, describing all of the ways Connecticut Valley will become an unbundled transmission customer of the Company subsequent to termination, and establishing the expected period of service based upon the date of termination, whenever that occurs, and the weighted average service life of its commitments to power resources to serve Connecticut Valley. Had termination taken effect on January 1, 1998 this expectation period would have equaled nineteen years. If the Company is unable to obtain an order authorizing the full recovery amount of the exit fee, or other appropriate mechanism, the Company would be required to recognize a loss under SFAS No. 5 totaling approximately $75.0 million on a pre-tax basis. Furthermore, the Company would be required to write-off approximately $4.0 million in regulatory assets associated with its wholesale business under SFAS No. 71 on a pre-tax basis. Conversely, even if the Company obtains a FERC order authorizing the updated requested exit fee, Connecticut Valley would be required to recognize a loss under SFAS No. 5 of approximately $54.9 million on a pre-tax basis unless Connecticut Valley has obtained an order by the NHPUC or other appropriate body directing the recovery of those costs in Connecticut Valley's retail rates. Either of these reasonably possible outcomes could occur during calendar year 1998. The Company has initiated and will continue to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC. The Company cannot predict the ultimate outcome of this matter. However, an adverse resolution would have a material adverse effect on the Company's results of operations, cash flows, and ability to obtain capital at competitive rates. Note 4 - Investment in Vermont Yankee Nuclear Power Corporation The Company accounts for its investment in Vermont Yankee using the equity method. Summarized financial information for Vermont Yankee Nuclear Power Corporation follows: Three Months Ended Six Months Ended June June 1998 1997 1998 1997 ---- ---- ---- ---- Operating revenues $57,913 $44,383 $109,083 $84,804 Operating income $ 3,950 $ 3,579 $ 7,710 $ 7,290 Net income $ 1,806 $ 1,748 $ 3,508 $ 3,523 Company's equity in net income $539 $545 $1,049 $1,101 CENTRAL VERMONT PUBLIC SERVICE CORPORATION Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS June 30, 1998 Earnings Overview The Company recorded losses available for common stock of $5.9 million and $2.4 million for the three months ended June 30, 1998 and 1997, respectively. Losses per share of common stock for these respective periods were $.52 and $.21. 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 second quarter earnings compared to the second quarter 1997 resulted primarily from higher net power costs. Second quarter 1998 power costs increased due to an extended refueling outage at the Vermont Yankee Nuclear Power Plant (after-tax impact of $1.6 million) and higher costs under the Hydro-Quebec power contract (after-tax impact of $1.9 million). For the six months ended June 30, 1998 earnings available for common stock were $3.8 million compared to $11.5 million in 1997. Earnings per share of common stock for these respective periods were $.34 and $1.00. Included in earnings available for common and earnings per share of common stock in the first six months of 1998 are the positive impact of reversing 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. (See Electric Industry Restructuring - New Hampshire below and Note 1 in Notes to Consolidated Financial Statements for more information.) Other factors affecting results for 1998 are described in Results of Operations below. Earnings available for common stock and earnings per share of common stock for the first six months of 1997 reflect an after-tax gain of $1.3 million and $.12, respectively, from a non-recurring asset sale. Absent the reversal of the fourth quarter 1997 charge of $3.6 million and the extraordinary credit of $.9 million, 1998's first six months net income would have been $.3 million, or a loss of $.05 per share of common stock. Net income for the first six months of 1997 absent the non-recurring asset sale was $11.2 million, or $.88 per share of common stock. RESULTS OF OPERATIONS The major elements of the Consolidated Statement of Income are discussed below. Operating Revenues and MWH Sales A summary of MWH sales and operating revenues for the three and six months ended June 30, 1998 and 1997 (and the related percentage changes from 1997) is set forth below:
Three Months Ended June 30 ------------------------------------------------ Percentage Percentage MWH Increase Revenues (000's) Increase 1998 1997 (Decrease) 1998 1997 (Decrease) ------- ------- ---------- ------- ------- ---------- Residential 212,368 217,173 (2.2) $24,428 $24,485 (.2) Commercial 224,336 216,060 3.8 23,181 22,138 4.7 Industrial 98,530 98,912 (.4) 7,361 7,154 2.9 Other retail 1,763 1,786 (1.3) 486 488 (.4) ------- ------- ------- ------- Total retail sales 536,997 533,931 .6 55,456 54,265 2.2 ------- ------- ------- ------- Resale sales: Firm 451 232 94.4 18 12 50.0 Entitlement 50,744 84,623 (40.0) 5,279 4,612 14.5 Other 144,081 187,203 (23.0) 4,217 4,970 (15.2) ------- ------- ------- ------- Total resale sales 195,276 272,058 (28.2) 9,514 9,594 (.8) ------- ------- ------- ------- Other revenues - - - 1,436 1,583 (9.3) ------- ------- ------- ------- Total sales 732,273 805,989 (9.1) $66,406 $65,442 1.5 ======= ======= ======= ======= Six Months Ended June 30 --------------------------------------------------- Percentage Percentage MWH Increase Revenues (000's) Increase 1998 1997 (Decrease) 1998 1997 (Decrease) --------- --------- ---------- -------- -------- ---------- Residential 476,829 492,460 (3.2) $ 59,605 $ 60,288 (1.1) Commercial 452,768 446,135 1.5 50,643 52,538 (3.6) Industrial 208,418 214,556 (2.9) 17,456 17,808 (2.0) Other retail 3,565 3,549 .5 969 959 1.0 --------- --------- -------- -------- Total retail sales 1,141,580 1,156,700 (1.3) 128,673 131,593 (2.2) --------- --------- -------- -------- Resale sales: Firm 1,125 497 126.4 37 23 60.9 Entitlement 135,756 195,486 (30.6) 10,263 9,567 7.3 Other 314,170 382,578 (17.9) 8,821 9,777 (9.8) --------- --------- -------- -------- Total resale sales 451,051 578,561 (22.0) 19,121 19,367 (1.3) --------- --------- -------- -------- Other revenues - - - 2,570 2,976 (13.6) --------- --------- -------- -------- Total sales 1,592,631 1,735,261 (8.2) $150,364 $153,936 (2.3) ========= ========= ======== ========
Retail MWH sales for the second quarter of 1998 were relatively flat compared to the second quarter of 1997, increasing only about .6%. This minimal increase resulted in a $1.2 million, or 2.2% increase in retail revenues. For the first half of 1998, retail MWH sales decreased 1.3% compared to the first half of 1997 reflecting moderate temperatures not typical of a Vermont winter. Retail revenues decreased $2.9 million, or 2.2% compared to last year. This negative variance during the first half of 1998 is attributable to a $1.6 million impact of lower MWH sales and $1.3 million resulting from a modified rate design 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. As a result, lower prices were charged during January through March 1998 than the comparable 1997 period. Entitlement MWH sales decreased 40.0% or 33,879 MWH for the second quarter compared to the same period in 1997. 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 resulting from the refueling and maintenance outage are passed on to entitlement customers causing an increase in entitlement revenues of $.7 million, or 14.5%. For the first half of 1998 entitlement MWH sales decreased 30.6% and related revenues increased 7.3%, or $.7 million compared to the first half of 1997 for reasons discussed above. The decrease in other resale sales and revenues for the second quarter and first half of 1998 resulted primarily from decreased off-system sales and sales to Nepool partially offset by an increase in short-term system capacity sales. The decrease in other revenues for the second quarter and first half of 1998 compared to the 1997 periods results primarily from lower revenues associated with 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 six months ended June 30, 1998 and 1997 are as follows (dollars in thousands):
Three Months Ended June 30 1998 1997 Units Amount Units Amount ----- ------ ----- ------ Purchased and produced: Capacity (MW) 565 $26,674 474 $23,170 Energy (MWH) 703,024 19,208 778,912 17,135 ------- ------- Total purchased power costs 45,882 40,305 Production fuel (MWH) 71,537 394 71,330 425 ------- ------- Total purchased power and production fuel costs 46,276 40,730 Entitlement and other resale sales (MWH) 194,825 9,496 271,826 9,582 ------- ------- Net purchased power and production fuel costs $36,780 $31,148 ======= ======= Six Months Ended June 30 1998 1997 Units Amount Units Amount ----- ------ ----- ------ Purchased and produced: Capacity (MW) 567 $47,115 499 $44,458 Energy (MWH) 1,539,300 38,473 1,704,976 36,843 ------- ------- Total purchased power costs 85,588 81,301 Production fuel (MWH) 146,612 909 132,056 691 ------- ------- Total purchased power and production fuel costs 86,497 81,992 Entitlement and other resale sales (MWH) 449,926 19,084 578,064 19,344 ------- ------- Net purchased power and production fuel costs $67,413 $62,648 ======= =======
Net purchased power and production fuel costs increased $5.6 million, or 18.1% for the second quarter of 1998 compared to the second quarter of 1997 primarily as the result of the extended Vermont Yankee refueling outage and higher costs under the Hydro-Quebec power contract. For the first half of 1998, net purchased power and production fuel costs increased $4.8 million, or 7.6% compared to the first half of 1997. However, absent the benefit of the 1997 Connecticut Valley reversal discussed above, net purchased power and production fuel costs increased $10.3 million, or 16.4% for 1998 compared to the same period last year. The $10.3 million variance is attributable to the Vermont Yankee extended refueling outage 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 $1.3 million on a pre-tax basis. Such amounts have not been paid or expended at this time. The Company believes that VELCO will prevail in its efforts to favorably resolve this matter with PSNH. 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 the first six months of 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 $5.9 million. Such costs will be deferred by Vermont Yankee and amortized over the remaining license life of the plant. Vermont Yankee has received unsolicited 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 deferred power contract obligations (current and non-current). Although the estimated costs of decommissioning are subject to change due to changing technologies and regulations, the Company expects that the nuclear generating companies' liability for decommissioning, including any future changes in the liability, will be recovered in their rates over their operating or license lives. The decision to prematurely retire these nuclear power plants was based on economic analyses of the costs of operating them compared to the costs of closing them and incurring replacement power costs over the remaining period of the plants' operating licenses. The Company believes that based on the current regulatory process, its proportionate share of Maine Yankee, Connecticut Yankee and Yankee Atomic decommissioning costs will be recovered through the regulatory process and, therefore, the ultimate resolution of the premature retirement of the three plants has not and will not have a material adverse effect on the Company's earnings or financial condition. Other Operation Other operating expenses increased $.7 million and $2.2 million for the second quarter and first half of 1998 principally due to an increase in distribution, customer accounts, consulting services and regulatory commission expenses partially offset by an increase in deferral of conservation and load management costs (C&LM). Maintenance The increase in maintenance expenses of $.9 million for the first half of 1998 compared to the same period in 1997 is attributable to the severe ice storm in January 1998. Income Taxes Federal and state income taxes fluctuate with the level of pre-tax earnings. The decrease in total income tax expense for the second quarter and first half of 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 second quarter and first half results from lower subsidiaries' earnings (see Diversification below) and a gain of $2.1 million from a non-recurring asset sale in February 1997. Extraordinary Credit The extraordinary credit net of taxes of $.9 million represents a reversal of a charge of a like amount taken in the fourth quarter of 1997 discussed above. Dividends Declared The decrease in common dividends declared results from an early declaration made in December 1997 for the quarterly dividend paid on February 13, 1998. LIQUIDITY AND CAPITAL RESOURCES 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 $6.4 million for the first six months of 1998 versus $38.5 million for the first six months of 1997. 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 six months of 1998 with cash and cash equivalents of $8.8 million, a decrease of $7.7 million from the beginning of the year. The decrease in cash for the first six months of 1998 was the result of $6.4 million provided by operating activities, offset by $8.3 million used for investing activities and $5.8 million used for financing activities. Operating Activities - Net income, depreciation and deferred income taxes and investment tax credits provided $16.2 million. About $9.8 million of cash was used for working capital needs and other operating activities. Investing Activities - Construction and plant expenditures consumed approximately $6.9 million, while $1.4 million was used for C&LM programs and non-utility investments. Financing Activities - Dividends paid on common stock were $5.0 million while preferred dividends were $.5 million. Short-term obligations required $.4 million and sale of Treasury Stock provided $.1 million. For related information see the Company's discussion on Financing and Capitalization below. ELECTRIC INDUSTRY RESTRUCTURING The electric utility industry is in a period of transition that may result in a shift away from ratemaking based on cost of service and return on equity to more market-based rates. Many states, including Vermont and New Hampshire, where the Company does business, are exploring new mechanisms to bring greater competition, customer choice and market influence to the industry while retaining the public benefits associated with the current regulatory system. Vermont On December 31, 1996, the PSB issued a Report and Order (the Report) outlining a restructuring plan (the Plan), subject to legislative approval, for the Vermont electric utility industry. Due to uncertainty surrounding legislative schedules, the PSB, on April 18, 1997, issued an Order which suspended, pending further legislative action or future PSB Orders, certain filing deadlines for reports and plans to be completed in connection with the Plan. 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. At this time, the task force has yet to take any official action. On July 23, 1998, the PSB announced a series of statewide workshops on the future of Vermont's regulated network industries including electricity. The workshops are intended to take a broad, strategic look at these industries, the services they provide, the problems regulated companies are facing and ways to reduce the cost of power supply in Vermont and improve service. Through these workshops, the PSB has promised to invite participants to present specific proposed actions for utilities, power marketers, and government to address the problem of increasing power costs in Vermont. These workshops will begin in late August and will continue through the fall of 1998. 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 affirms, clarifies and modifies various generic policy statements including the reaffirmation to establish rates on the basis of a regional average announced previously in its February 28, 1997 Final Plan. The March 20, 1998 order also addressed all outstanding motions for rehearings or clarification relative to the policies or legal positions articulated in the Final Plan and removes the stay covering the Company's interim stranded cost order of April 7, 1997. In addition, the March 20, 1998 Order imposed various compliance filing requirements. On November 17, 1997, the City of Claremont, New Hampshire (Claremont), filed with the NHPUC a petition for a reduction in Connecticut Valley's electric rates. Claremont based its request on the NHPUC's earlier finding that Connecticut Valley's failure to terminate its wholesale power contract with the Company as ordered in the NHPUC Stranded Cost Order of February 28, 1997 was imprudent. Under the wholesale power purchase contract with the Company, Connecticut Valley may terminate service at the end of a service year, provided it has given written notice of termination prior to the beginning of that service year. Claremont alleges that if Connecticut Valley had given written notice of termination to the Company in 1996 when legislation to restructure the electric industry was enacted in New Hampshire, Connecticut Valley's obligation to purchase power from the Company would have terminated as of January 1, 1998. On November 26, 1997, Connecticut Valley filed a request with the NHPUC to increase the FAC, PPCA and short-term energy purchase rates effective on or after January 1, 1998. The requested increase in rates resulted from higher forecast energy and capacity charges on power Connecticut Valley purchases from the Company plus removal of a credit effective during 1997 to refund overcollections from 1996. Connecticut Valley objected to the NHPUC's notice of intent to consolidate Claremont's petition into the FAC and PPCA docket, stating that Claremont's complaint should be heard as part of the NHPUC restructuring docket. Over Connecticut Valley's objection at the hearing on December 17, 1997, the NHPUC consolidated Claremont's petition with Connecticut Valley's FAC and PPCA proceeding. In an Order dated December 31, 1997 in Connecticut Valley's FAC and PPCA docket, the NHPUC found Connecticut Valley acted imprudently by not terminating the wholesale contract between Connecticut Valley and the Company, notwithstanding the stays of its February 28, 1997 Orders. The NHPUC Order further directed Connecticut Valley to freeze its current FAC and PPCA rates (other than short term rates to be paid to certain Qualifying Facilities) effective January 1, 1998, on a temporary basis, pending a hearing to determine: 1) the appropriate proxy for a market price that Connecticut Valley could have obtained if it had terminated its wholesale contract with the Company; 2) the implications of allowing Connecticut Valley to pass on to its customers only that market price; and 3) whether the NHPUC's final determination on the FAC and PPCA rates should be reconciled back to January 1, 1998 or some other date. On January 19, 1998, Connecticut Valley and the Company filed with the Federal District Court for a temporary restraining order to maintain the status quo ante by staying the December 31, 1997 NHPUC Order and preventing the NHPUC from taking any action that (i) compromises cost-based rate making for Connecticut Valley or otherwise seeks to impose market price-based rate making on Connecticut Valley; (ii) interferes with the FERC's exclusive jurisdiction over the Company's pending application to recover wholesale stranded costs upon termination of its wholesale power contract with Connecticut Valley; or (iii) prevents Connecticut Valley from recovering through retail rates the stranded costs and purchased power costs that it incurs pursuant to its FERC-authorized wholesale rate schedule with the Company. On February 23, 1998, the NHPUC announced in a public meeting that it reaffirmed its finding of imprudence and would designate a proxy market price for power at 4 cents per kWh in lieu of the actual costs incurred pursuant to the wholesale power contract with the Company. In addition, the NHPUC indicated, subject to certain conditions 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. Also, on April 3, 1998, the Court indicated that its TRO enjoining the NHPUC's restructuring orders applied to Connecticut Valley and prohibits the enforcement of the restructuring orders until the Court conducts a consolidated hearing and rules on the requests for permanent injunctive relief by plaintiff PSNH and the other utilities that have been allowed to intervene in these proceedings, including the Company and Connecticut Valley. The plaintiffs-intervenors filed a motion asking the Court to extend its stay of action by the NHPUC to implement restructuring and to make clear that the stay encompasses the NHPUC's order of March 20, 1998. As a result of these Court orders, Connecticut Valley's 1997 charges under SFAS No. 5 and SFAS No. 71 described above were reversed in the first quarter of 1998. Combined, the reversal of these charges increased first quarter 1998 net income and earnings per share of common stock by approximately $4.5 million and $.39, respectively. On April 1, 1998, Citizens Bank of New Hampshire (Bank) notified Connecticut Valley that it was in default of the Loan Agreement between the Bank and Connecticut Valley dated December 27, 1994 and that the Bank will exercise all of its remedies from and after May 5, 1998 in the event that the violations are not cured. After reversing the 1997 write-offs described above, Connecticut Valley 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 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. On June 25, 1997, the Company filed with the FERC a notice of termination of its power supply contract with Connecticut Valley, conditional upon the Company's request to impose a surcharge on the Company's transmission tariff to recover the stranded costs that would result from the termination of its contract with Connecticut Valley. The amount requested was $44.9 million plus interest at the prime rate to be recovered over a ten-year period. In its Order dated December 18, 1997 in Docket No. ER97-3435-000, the FERC rejected the Company's proposed stranded cost surcharge mechanism but indicated that it would consider an exit fee mechanism for collecting stranded costs. The FERC also rejected the Company's arguments concerning the applicability of stated FERC policies regarding retail stranded costs, multi-state regulatory gaps and the implications of state restructuring initiatives. The Company has filed a motion seeking rehearing of the FERC's December 18, 1997 Order. In addition, and in accordance with the December 18, 1997 FERC Order, on January 12, 1998 the Company filed a request with the FERC for an exit fee mechanism to collect $44.9 million in a lump sum, or in installments with interest at the prime rate over a ten-year period, to cover the stranded costs resulting from the cancellation of Connecticut Valley's power contract with the Company. On March 11, 1998, the FERC issued an order accepting for filing the Company's request for an exit fee effective March 14, 1998, and set hearings to determine: whether Connecticut Valley will become an unbundled transmission customer of the Company, the Company's expectation as to the period of time it would serve Connecticut Valley, and the allowable amount of the exit fee. The FERC also rejected the Company's June 25, 1997 notice of termination indicating that the notice can be resubmitted when the power contract is proposed to be terminated. On April 28, 1998, the Company filed its case-in-chief before the FERC updating the amount of the exit fee to $54.9 million in a lump sum, describing all of the ways Connecticut Valley will become an unbundled transmission customer of the Company subsequent to termination, and establishing the expected period of service based upon the date of termination, whenever that occurs, and the weighted average service life of its commitments to power resources to serve Connecticut Valley. Had termination taken effect on January 1, 1998 this expectation period would have equaled nineteen years. If the Company is unable to obtain an order authorizing the full recovery amount of the exit fee, or other appropriate mechanism, the Company would be required to recognize a loss under SFAS No. 5 totaling approximately $75.0 million on a pre-tax basis. Furthermore, the Company would be required to write-off approximately $4.0 million in regulatory assets associated with its wholesale business under SFAS No. 71 on a pre-tax basis. Conversely, even if the Company obtains a FERC order authorizing the updated requested exit fee, Connecticut Valley would be required to recognize a loss under SFAS No. 5 of approximately $54.9 million on a pre-tax basis unless Connecticut Valley has obtained an order by the NHPUC or other appropriate body directing the recovery of those costs in Connecticut Valley's retail rates. Either of these reasonably possible outcomes could occur during calendar year 1998. For further information on New Hampshire restructuring issues and other regulatory events in New Hampshire affecting the Company or Connecticut Valley and the December 1997 charges and reversals of the charges, see the Company's Form 8-K dated January 12, 1998, January 28, 1998 and April 1, 1998; and Item 1. Business-New Hampshire Retail Rates, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Electric Industry Restructuring-New Hampshire and Item 8. Financial Statements and Supplementary Data-Note 13, Retail Rates-New Hampshire in the Company's 1997 Form 10-K. The Company has initiated and will continue to work for a negotiated settlement with parties to the New Hampshire restructuring proceeding and the NHPUC. The Company cannot predict the ultimate outcome of this matter. However, an adverse resolution 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 $73.0 million on a pre-tax basis as of June 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 December 31, 1997, based upon the regulatory environment within which the Company currently operates, SFAS No. 121 did not have an impact on the Company's financial position or results of operations. Competitive influences or regulatory developments may impact this status in the future. Because the Company is unable to predict what form possible future restructuring legislation will take, it cannot predict if or to what extent SFAS Nos. 71 and 121 will continue to be applicable in the future. In addition, if the Company is unable to mitigate or otherwise recover stranded costs that could arise from any potentially adverse legislation or regulation, the Company would have to assess the likelihood and magnitude of losses incurred under SFAS No. 5. As such, the Company cannot predict whether any restructuring legislation enacted in Vermont or New Hampshire, once implemented, would have a material adverse effect on the Company's operations, financial condition or credit ratings. However, the Company's failure to recover a significant portion of its purchased power costs, would likely have a material adverse effect on the Company's results of operations, cash flows and ability to obtain capital at competitive rates. It is possible that stranded cost exposure associated with SFAS Nos. 5, 71, and 121, before mitigation could exceed the Company's current total common stock equity. FINANCING AND CAPITALIZATION Utility The level of short-term borrowings fluctuates based on seasonal corporate needs, the timing of long-term financings and market conditions. On November 5, 1997 the Company entered into an unsecured $50 million, 364 day committed Revolving Credit and Competitive Advance Facility (Credit Facility) with a group of banks. With the approval of this facility by the PSB on April 2, 1998, it became a three-year facility with two one-year options. However, due to the February 27, 1998 Order issued by the PSB in the Green Mountain Power Corporation rate proceeding, the banks participating in this Credit Facility have determined that a material adverse change occurred in the Company's financial prospects. Such a condition would prevent borrowings under the Credit Facility. In addition, three letters of credit with expiry dates between May and December 1999 supporting $16.3 million of long-term debt of the Company will likely not be rolled over by the issuing bank, which is the Agent Bank on the $50 million Credit Facility, if such material adverse change is continuing when those expiry dates occur in 1999. One letter of credit supporting $5.8 million expires May 1, 1999 and two letters of credit supporting $10.5 million expire December 1 and 2, 1999. Negotiations with the banks participating in the Credit Facility have resulted in an understanding, subject to documentation and regulatory approval, of modifications to the Credit Facility. Those major changes are: 1) a second mortgage interest in the Company's utility fixed assets; 2) a revised maturity date of June 1, 1999 (the original agreement was to end in November 2000) with yearly renewals at the banks' discretion; 3) a 25 basis point increase in interest rates on borrowings; 4) the application of any proceeds from the issuance of any First Mortgage Bonds during the term of the Credit Facility to the concurrent repayment of any outstanding loans thereunder as well as the reduction of the aggregate commitment of the Credit Facility; and 5) a 25 basis point increase in the cost of the $16.3 million aggregate amount of letters of credit. During the period in which documentation and regulatory approval of these changes are being completed, the banks have agreed to provide up to $10 million on an unsecured basis through June 1, 1999. At June 30, 1998, the Company had outstanding approximately $.3 million under this Credit Facility. The Company has $20.5 million of scheduled first mortgage debt repayments in December 1998. The Company anticipates those cash requirements will be met out of borrowings under the Credit Facility. The borrowings under the Credit Facility are expected to be approximately $25 million by May 1999, just prior to the June 1, 1999 expiration and repayment date on the Credit Facility. In addition, the Company will be required to roll over an aggregate of $16.3 million of letters of credit expiring in May 1999 and December 1999. The Company's ability to refinance the expected $25.0 million of outstanding borrowings in May 1999, roll over the approximately $16.3 million of letters of credit in 1999 and reinstate a new Credit Facility will be largely dependant on a positive outcome of the Company's pending rate increase requests. Connecticut Valley maintained a $.8 million committed line of credit for its construction program and for other corporate purposes which expired on May 31, 1998. Connecticut Valley had no outstanding short-term debt at June 30, 1998. Connecticut Valley is currently renegotiating with Citizens Bank of New Hampshire to renew this line of credit on a secured basis. Connecticut Valley has outstanding long-term bank debt of $3.75 million expiring December 27, 1999, and is negotiating with Citizen's Bank to secure and extend this facility. The Company's capital structure ratios as of June 30, 1998 (including amounts of long-term debt due within one year) consisted of 51.7% common equity, 7.5% preferred stock and 40.8% long-term debt including capital lease obligations. Current credit ratings of the Company's securities as reaffirmed by Duff & Phelps and Standard & Poor's are as follows: Duff & Standard Phelps & Poor's ------ -------- First Mortgage Bonds BBB A- Corporate Credit Rating BBB Preferred Stock BBB- BBB- On January 22, 1998, Standard & Poor's revised its ratings outlook on the Company to negative from stable stating that the revised outlook reflects the adverse ruling by the NHPUC related to Connecticut Valley discussed above. Non-Utility Catamount, a wholly owned subsidiary of the Company, implemented a credit facility in July 1996 which provides for up to $8.0 million of letters of credit and working capital loans. Currently, a $1.2 million letter of credit is outstanding to support certain of Catamount's obligations in connection with a debt reserve requirement in the Appomattox Cogeneration project. Financial obligations of the non-utility wholly owned subsidiaries are non-recourse to the Company. C&LM Programs The primary purpose of these programs is to offset the need for long-term power supply and delivery resources that are more expensive to purchase or develop than customer-efficiency programs. Total C&LM expenditures in 1997 were $2.7 million and are expected to be $1.7 million for 1998. Diversification Catamount was formed for the purpose of investing in non-regulated power plant projects. Currently, Catamount, through its wholly owned subsidiaries, has interests in five operating independent power projects located in Glenns Ferry and Rupert, Idaho; Rumford, Maine; East Ryegate, Vermont; and Hopewell, Virginia. In addition, Catamount has interests in two projects under construction in Thetford and Fort Dunlop, England, and a project under development in Summersville, West Virginia. Catamount's after-tax earnings were $.6 million and $.5 million for the second quarter of 1998 and 1997, respectively, and $1.3 million and $1.0 million for the first half 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 $.5 million and $3 thousand for the second quarter of 1998 and 1997, respectively, and losses of $.9 million and earnings of $.04 million for the first half of 1998 and 1997, respectively. These losses result from activities that will allow SmartEnergy to enter several niches of the national and international energy market. SmartEnergy has signed an agreement to manufacture and deliver the SmartDrive dairy vacuum pump control to domestic and worldwide markets beginning later this year. 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. New Hampshire: On November 26, 1997, Connecticut Valley filed a request with the NHPUC to increase the FAC, PPCA and short-term energy purchase rates effective on or after January 1, 1998. The requested increase in rates results from higher forecast energy and capacity charges on power Connecticut Valley purchases from the Company plus removal of credit effective during 1997 to refund overcollections from 1996. In an order dated December 31, 1997, the NHPUC directed Connecticut Valley to freeze its current FAC and PPCA rates (other than short-term rates to be paid to certain Qualifying Facilities) effective January 1, 1998, on a temporary basis pending a hearing to determine: 1) the appropriate proxy for a market price that Connecticut Valley could have obtained if it had terminated its wholesale contract with the Company; 2) the implications of allowing Connecticut Valley to pass on to its customers only that market price; and 3) whether the NHPUC's final determination on the FAC and PPCA rates should be reconciled back to January 1, 1998 or some other date. For additional information on Vermont and New Hampshire rate and regulatory matters see Electric Industry Restructuring discussed above and Note 3 to the Consolidated Financial Statements. Year 2000 Information Systems Modifications The Company has assessed the impact of the year 2000 issue on its computer systems and applications. During 1997, the Company incurred costs of approximately $.1 million and estimates that about $2.5 million will be incurred in 1998 and $.2 million will be incurred in 1999 to modify its existing computer systems and applications which are expected to be completed during the second quarter of 1999. During the first quarter of 1998, the Company requested an accounting order from the PSB to defer these operating and maintenance costs. By letter dated June 10, 1998, the PSB declined to issue the requested accounting order, and directed the Company to recognize the Year 2000 costs in the period in which they occurred. The PSB also opened a generic proceeding into Year 2000 readiness and compliance costs, including the appropriate accounting treatment for those costs, for all Vermont utilities. On June 23, 1998, the Company asked the PSB to reconsider its decision with respect to the Company. On July 21, 1998, members of the PSB met with the Company's representatives and of the Vermont Department of Public Service to discuss the issues involved. As a result, the letter signed by the PSB denying the accounting treatment requested by the Company was thereby rescinded. The PSB will reconsider the issuance of an accounting order, and the Company anticipates that a final determination by the PSB will be issued by the end of the third quarter of 1998. The Company believes that based on the current regulatory process, these costs will be recovered through the regulatory process and therefore they do not represent the potential for a material adverse effect on its financial position or results of operations. 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. An independent analysis on these areas began during the first quarter of 1998 and a final report is expected during the third quarter of 1998. 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. 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. 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 names as defendants a number of insurance companies that issued policies to the Company dating from the mid 1940s to the late 1980s. The Company asserts that policies issued by defendants provide coverage for all defense and remediation costs associated with the Cleveland Avenue property, the Bennington Landfill site and the North Clarendon site. With the exception of the North Clarendon site, no further remediation is anticipated. See Note 2 to the Consolidated Financial Statements for related disclosures. On August 7, 1997, the Company and eight other non-operating owners of Unit #3 filed a demand for arbitration with Connecticut Light and Power Company and Western Massachusetts Electric Company and lawsuits against NU and its trustees. The arbitration and lawsuits seek to recover costs associated with replacement power, operation and maintenance costs and other costs resulting from the shutdown of Unit #3. The non-operating owners claim that NU and two of its wholly owned subsidiaries failed to comply with NRC's regulations, failed to operate the facility in accordance with good operating practice and attempted to conceal their activities from the non-operating owners and the NRC. Except as otherwise described under Management's Discussion and Analysis of Financial Condition and Results of Operations, Item 2, there are no other material pending legal proceedings, other than ordinary routine litigation incidental to the business, to which the Company or any of its subsidiaries is a party or to which any of their property is subject. Items 2, 3 and 4. None. Item 5. Other Information. (a) Effective July 20, 1998, Delano E. Lewis was elected to the Company's Board of Directors to replace Preston Leete Smith, who chose to retire early. (b) Date for Submission of Stockholder Proposals for 1999 Annual Meeting of Stockholders - A stockholder desiring to present a proposal at the Company's 1999 Annual Stockholders' Meeting and to have such proposal considered for inclusion in the proxy materials for such meeting should submit such proposal addressed to the Secretary, Joseph M. Kraus, no later than November 21, 1998. Any such proposal must comply with Rule 14a-8 of Regulation 14A of the proxy rules of the Securities and Exchange Commission and will be omitted from or included in the proxy material at the discretion of the Board of Directors of the Company in accordance with such applicable laws and regulations. Item 6. Exhibits and Reports on Form 8-K. (a) List of Exhibits 10. Material Contracts * 10.83.1 First Amendment to Credit Agreement Dated as of April 15, 1998 * 10.83.2 Second Amendment to Credit Agreement Dated as of June 2, 1998 27. Financial Date Schedule. (b) Item 5. Other Events, Form 8-K dated April 1, 1998 was filed on April 30, 1998 re: (1) Preliminary Injunction Stays New Hampshire Rate Order (2) Vermont Retail Rate Case (3) Revolving Credit and Competitive Advance Facility 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 August 7, 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 6-MOS DEC-31-1998 JUN-30-1998 PER-BOOK 319,653 64,164 53,430 78,303 0 515,550 66,105 45,307 74,646 186,058 18,000 8,054 108,839 250 0 0 20,521 1,000 16,682 1,094 155,052 515,550 150,364 2,013 141,751 143,764 6,600 2,598 9,198 5,259 4,812 973 3,839 5,034 4,020 6,397 .34 .34
EX-10 3 EXHIBIT 10.83.1 EXHIBIT 10.83.1 --------------- FIRST AMENDMENT TO CREDIT AGREEMENT FIRST AMENDMENT, dated as of April 15, 1998 (this "Amendment"), to the Credit Agreement referred to below by and among CENTRAL VERMONT PUBLIC SERVICE CORPORATION, a Vermont corporation ("Borrower"), each of the lenders that is a signatory to the Credit Agreement or which, pursuant to Section 10.6 thereof shall become a "Lender" thereunder (the "Lenders"), FLEET NATIONAL BANK, as syndication agent (the "Syndication Agent") and TORONTO DOMINION (TEXAS), INC., as agent for the Lenders hereunder (the "Agent"; Lenders, Syndication Agent and Agent are sometimes collectively referred to herein as the "Lending Group"). WITNESSETH WHEREAS, Borrower and Lending Group are parties to that certain Credit Agreement, dated as of November 5, 1997 (as amended, supplemented or otherwise modified from time to time, the "Credit Agreement"); and WHEREAS, Borrower and Lending Group have agreed to amend the Credit Agreement in the manner, and on the terms and conditions, provided for herein in order to clarify certain ambiguities therein to better reflect the intentions of the parties. NOW THEREFORE, in consideration of the premises and for other good and valuable consideration, the receipt, adequacy and sufficiency of which are hereby acknowledged, Borrower and Lending Group hereby agree as follows: 1. Definitions. Capitalized terms not otherwise defined herein shall have the meanings ascribed to them in the Credit Agreement. 2. Amendment to Section 5.2 of the Credit Agreement. Section 5.2 of the Credit Agreement is hereby amended by adding a new subsection (e) immediately following subsection (d) thereto to read as follows: "(e) No Material Adverse Effect. No fact has become known to the Borrower which has had or in the reasonable judgment of the Borrower may in the future have a materially adverse effect on the business, operations, assets, liabilities, financial condition, results of operations or business prospects of the Borrower or on its ability to perform its obligations under this Agreement or the Existing Letter of Credit Agreements since the Closing Date." 3. No Other Amendments. Except as expressly amended, herein, each of the Credit Agreement and the other Loan Documents shall be unmodified and shall continue to be in full force and effect in accordance with its terms. 4. Effectiveness. This Amendment shall become effective as of the date hereof. 5. GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK. 6. Counterparts. This Amendment may be executed by the parties hereto on any number of separate counterparts and all of said counterparts taken together shall be deemed to constitute one and the same instrument. (SIGNATURE PAGE FOLLOWS) IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered as of the day and year first above written. Borrower: CENTRAL VERMONT PUBLIC SERVICE CORPORATION By: /s/ Francis J. Boyle Francis J. Boyle Senior Vice President, Chief Financial Officer and Treasurer Agent: TORONTO DOMINION (TEXAS), INC. By: /s/ Jano Mott Jano Mott Vice President Lenders: TORONTO DOMINION (NEW YORK), INC. By: /s/ Debbie A. Greene Debbie A. Greene Vice President BANKBOSTON, N.A. By: /s/ Virginia Ryan Virginia Ryan Vice President FLEET NATIONAL BANK By: /s/ Robert D. Lanigan Robert D. Lanigan Director CITIZENS BANK NEW HAMPSHIRE By: /s/ Vernon T. Studer Vernon T. Studer Vice President EX-10 4 EXHIBIT 10.83.2 EXHIBIT 10.83.2 --------------- SECOND AMENDMENT TO CREDIT AGREEMENT SECOND AMENDMENT, dated as of June 2, 1998 (this "Amendment"), to the Credit Agreement referred to below by and among CENTRAL VERMONT PUBLIC SERVICE CORPORATION, a Vermont corporation ("Borrower"), each of the lenders that is a signatory to the Credit Agreement or which, pursuant to Section 10.6 thereof shall become a "Lender" thereunder (the "Lenders"), FLEET NATIONAL BANK, as syndication agent (the "Syndication Agent") and TORONTO DOMINION (TEXAS), INC., as agent for the Lenders hereunder (the "Agent"; Lenders, Syndication Agent and Agent are sometimes collectively referred to herein as the "Lending Group"). WITNESSETH WHEREAS, the Borrower and the Lending Group are parties to that certain Credit Agreement, dated as of November 5, 1997 (as amended, supplemented or otherwise modified from time to time, the "Credit Agreement"); and WHEREAS, the Borrower and the Lending Group have agreed to amend the Credit Agreement in the manner, and on the terms and conditions, provided for herein. NOW THEREFORE, in consideration of the premises and for other good and valuable consideration, the receipt, adequacy and sufficiency of which are hereby acknowledged, the Borrower and the Lending Group hereby agree as follows: 1. Definitions. Capitalized terms not otherwise defined herein shall have the meanings ascribed to them in the Credit Agreement. 2. Amendments to the Credit Agreement. (a) Section 1.1 of the Credit Agreement is hereby amended by (1) inserting the text "0.25% plus" immediately prior to the text "the greater of" appearing in the first sentence of the definition of "ABR". (b) Section 1.1 of the Credit Agreement is hereby further amended by deleting in its entirety the table appearing in the definition of "Applicable Margin" and inserting in lieu thereof the following new table and text: "Debt Rating Applicable Margin BB (or lower) 1.00% BB+ 0.75% BBB- 0.55% BBB 0.475% BBB+ 0.435% A- 0.40% A (or higher) 0.375%" (c) Section 1.1 of the Credit Agreement is hereby further amended by deleting in its entirety the definition of "Maturity Date" appearing therein and inserting in lieu thereof the following new definition: "Maturity Date" shall mean June 1, 1999, unless extended as provided in Section 2.6(b), in which case the Maturity Date shall mean June 1, 2000, June 1, 2001, June 1, 2002 or November 5, 2002, as the case may be. (d) Section 1.1 of the Credit Agreement is hereby further amended by inserting in appropriate alphabetical order the following new definition: "Aggregate Commitment Increase Date" means the date on which all of the following conditions are satisfied: (i) the Loans and all other obligations of the Borrower to the Agent and the Lenders pursuant to the Loan Documents shall have been secured by a duly perfected second priority security interest in all the properties and other assets that secure the First Mortgage Bonds (the "Collateral"), subject only to the security interest in favor of the holders of the First Mortgage Bonds, and such documentation as shall be reasonably required by the Agent and the Lenders to evidence the granting of such second priority security interest (the "Security Documentation") shall have been duly executed and delivered by the parties thereto; (ii) the parties hereto shall have executed an amendment to the Credit Agreement (the "Amendment"), in form and substance satisfactory to the Agent and the Lenders, reflecting the provisions set forth in the Summary of Terms and Conditions attached hereto as Schedule 2 (including, without limitation, the granting of such second priority security interest in the Collateral), and such amendment shall be in full force and effect; (iii) the Borrower shall have received the approval of the Vermont Public Service Board and the approval of or waiver by any other state regulatory body with jurisdiction, in each case required for (x) (A) the 0.25% increase in the ABR and the Applicable Margin and (B) the extensions of the Maturity Date, in each case effected by the Second Amendment to this Agreement and (y) the grant of the security interest to the Lenders in the Collateral; (iv) the Agent shall have received evidence that all other actions necessary or, in the opinion of the Agent and its counsel, desirable to perfect and protect the security interest purported to be created by the Security Documentation have been taken; and (v) the Agent shall have received such legal opinions and other certificates as the Agent may reasonably request relating to the Security Documentation, the security interest taken in the Collateral and the Amendment. "Second Amendment Consent Date" shall mean the date on which the Borrower shall have received the approval of the Vermont Public Service Board and the approval of or waiver by any other state regulatory body with jurisdiction, in each case required for (x) the 0.25% increase in the ABR and the Applicable Margin and (y) the extensions of the Maturity Date, in each case effected by the Second Amendment to this Agreement. (e) Section 2.3(a) of the Credit Agreement is hereby amended by inserting immediately after the table appearing therein the following new text: "Notwithstanding anything to the contrary set forth herein, solely for purposes of calculating the above facility fee, the Aggregate Commitment Increase Date shall be deemed to have occurred." (f) Section 2.3(c) of the Credit Agreement is hereby amended by deleting the word "If" appearing at the beginning of such Section, and inserting in lieu thereof the new text "At any time on and after the Aggregate Commitment Increase Date, if". (g) Section 2.6 of the Credit Agreement is hereby amended by deleting in their entirety paragraphs (b) and (c) thereof, and inserting in lieu thereof the following new paragraph (b): "(b) So long as (i) no Default or Event of Default has occurred and is continuing, (ii) there has been no material adverse change in the business or financial condition of the Borrower since the date of the Second Amendment to this Agreement, (iii) the Second Amendment Consent Date shall have occurred and (iv) the Borrower has delivered to the Agent such evidence thereof as the Agent may reasonably request, then upon June 1, 1999 and each of the first, second and third anniversaries thereof, the Borrower may, at its option, subject to the approval of all of the Lenders, extend the Maturity Date for an additional one-year period, provided that in the case of any such extension of the Maturity Date beyond June 1, 2002 such Maturity Date shall be extended for a period ending on November 5, 2002." (h) Section 5.2(e) of the Credit Agreement is hereby amended by deleting the text "the Closing Date" appearing therein and inserting the text "(x) the date of the Second Amendment to this Agreement" in lieu thereof. (i) The Credit Agreement is hereby further amended by deleting in its entirety Schedule 1 attached thereto and inserting in lieu thereof Schedule 1 attached hereto. 3. No Other Amendments. Except as expressly amended, herein, each of the Credit Agreement and the other Loan Documents shall be unmodified and shall continue to be in full force and effect in accordance with its terms. 4. Effectiveness. This Amendment shall become effective as of the date hereof. 5. GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK. 6. Counterparts. This Amendment may be executed by the parties hereto on any number of separate counterparts and all of said counterparts taken together shall be deemed to constitute one and the same instrument. (SIGNATURE PAGE FOLLOWS) IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered as of the day and year first above written. Borrower: CENTRAL VERMONT PUBLIC SERVICE CORPORATION By: /s/ Francis J. Boyle Francis J. Boyle Sr. Vice President, CFO, Treasurer Agent: TORONTO DOMINION (TEXAS), INC. By: /s/ Jano Mott Jano Mott Vice President Lenders: TORONTO DOMINION (NEW YORK), INC. By: /s/ Jorge A. Garcia Jorge A. Garcia Vice President BANKBOSTON, N.A. By: /s/ Virginia Ryan Virginia Ryan Vice President FLEET NATIONAL BANK By: /s/ Robert D. Lanigan Robert D. Lanigan Director CITIZENS BANK NEW HAMPSHIRE By: /s/ Vernon T. Studer Vernon T. Studer Vice President Schedule 1 COMMITMENTS OF THE LENDERS At any time during the period ending on the Aggregate Commitment Increase Date: Lender: Toronto Dominion (New York), Inc. Address: 909 Fanin Houston, TX 77010 Commitment: $3,000,000 Commitment Percentage: 30% Lender: BankBoston Address: 100 Federal Street Boston, MA 02110 Commitment: $2,000,000 Commitment Percentage: 20% Lender: Citizens Bank Address: 20 West Park Street Lebanon, NH 03766 Commitment: $1,500,000 Commitment Percentage: 15% Lender: Fleet National Bank Address: One Federal Street Boston, MA 02110 Commitment: $3,500,000 Commitment Percentage: 35% Total Commitment: $10,000,000 Total Commitment Percentage: 100% At any time on and after the Aggregate Commitment Increase Date: Lender: Toronto Dominion (New York), Inc. Address: 909 Fanin Houston, TX 77010 Commitment: $15,000,000 Commitment Percentage: 30% Lender: BankBoston Address: 100 Federal Street Boston, MA 02110 Commitment: $10,000,000 Commitment Percentage: 20% Lender: Citizens Bank Address: 20 West Park Street Lebanon, NH 03766 Commitment: $7,500,000 Commitment Percentage: 15% Lender: Fleet National Bank Address: One Federal Street Boston, MA 02110 Commitment: $17,500,000 Commitment Percentage: 35% Total Commitment: $50,000,000 Total Commitment Percentage: 100% Schedule 2 CENTRAL VERMONT PUBLIC SERVICE CORPORATION CREDIT FACILITIES Summary of Terms and Conditions May 20, 1998 Reference is made to (i) that certain Credit Agreement, dated as of November 5, 1997 (as amended by the First Amendment thereto, dated as of April 15, 1998, the "Credit Agreement" capitalized terms defined therein being used herein as therein defined) among Central Vermont Public Service Corporation (the "Company"), the lenders from time to time party thereto (the "Lenders") and Toronto Dominion (Texas), Inc., as agent for the Lenders (in such capacity, the "Agent") and (ii) (A) the Amended and Restated Reimbursement Agreement, dated as of September 24, 1992, as amended, between the Company and The Toronto-Dominion Bank, through its Houston Office (the "Bank"), (B) the Reimbursement Agreement, dated as of April 29, 1993, as amended, between the Company and Central Vermont Public Service Corporation - East Barnet Hydroelectric, Inc., together with the Company's guaranty related thereto, and (C) the Letter of Credit and Reimbursement Agreement, dated as of November 1, 1994, as amended, between the Company and the Bank (collectively, the "Reimbursement Agreements"). The following represents an outline of proposed modifications to the Credit Agreement (the "Amendment") and to each of the Reimbursement Agreements (collectively, the "Reimbursement Agreement Amendments") in connection with, among other things, the Company providing collateral to secure the Company's obligations under the Loan Documents and the Reimbursement Agreements. The following is for discussion purposes only and is not a commitment on the part of the Agent or any Lender to modify the Credit Agreement or any other Loan Document, or on the part of the Bank to modify the Reimbursement Agreements or to waive any provision thereof or to take or omit to take any action and any such agreement on the part of the Agent, any Lender or the Bank would be in a separate written instrument signed by the Agent, each Lender and the Bank, as the case may be, following satisfactory completion of their due diligence, internal review and approval process. Without limiting the foregoing, it is currently contemplated that except as set forth below the Credit Agreement, the other Loan Documents and the Reimbursement Agreements will remain substantially unchanged. I. AMENDMENT GENERAL PROVISIONS Maturity: The Maturity Date shall be amended to June 1, 1999. Subject to the unanimous approval of all of the Lenders in their sole discretion and of the Company, the Maturity Date may be extended for one year on each anniversary thereof. Interest Rate: After giving effect to the Amendment, each Revolving Loan shall bear interest at a rate .25% higher than would otherwise be applicable absent the Amendment. Collateral: The Loans and all other obligations of the Company to the Agent and the Lenders pursuant to the Loan Documents shall be secured by a perfected second priority security interest in all of the properties and other assets that secure the First Mortgage Bonds (the "Collateral"), subject only to the security interest in favor of the holders of the First Mortgage Bonds (the "Bondholders"). The Company will grant such second priority security interest in favor of the Agent on behalf of the Lenders pursuant to documentation (the "Security Documentation") reasonably satisfactory to the Lenders. Without limiting the foregoing, it is currently contemplated that such documentation will be substantively the same as the Indenture of Mortgage pursuant to which the First Mortgage Bonds have been issued, as supplemented from time to time (the "First Mortgage Indenture"), including with respect to additional representations, warranties and covenants, except for changes necessitated by the relative priorities of the security interests granted in favor of the Bondholders and those granted in favor of the Lenders and other changes mutually agreed to by the Company and the Lenders; provided, however, that for purposes of the issuance of additional indebtedness and the release of property from the lien granted under the Security Documentation, the Company shall not have breached any of its warranties or covenants to the Lenders if it has satisfied the applicable requirements under the First Mortgage Indenture and, provided, further, that if the Company has satisfied the requirement under the First Mortgage Indenture to release property thereunder, the Agent shall release such property from the lien granted under the Security Documentation upon such release under the First Mortgage Indenture; and, provided, further, that the Company shall not be required to satisfy specific issuance tests with respect to the incurrence of additional indebtedness with each borrowing under the Credit Agreement as amended by the Amendments. Unsecured Borrowing: Until such time as the Company shall have received the approval of the Vermont Public Service Board required for the grant of the security interest to the Lenders as described under "Collateral" above, the Company shall be entitled to borrow on an unsecured basis, in one or more borrowings an aggregate amount at any one time outstanding not in excess of $10,000,000, which borrowings shall accrue interest at the rate provided under the Credit Agreement, as amended by the provision referred to under "Interest Rate" above. If the accrual of interest at such higher rates is subject to the approval of the Vermont Public Service Board, such borrowings shall accrue interest at the current rates and the Company shall pay a fee to the Lenders at the time such approval is obtained equal to the increased compensation the Lenders would have received had such borrowings borne interest at the higher rates. Mandatory Commitment Reductions and Prepayments Upon Future Bond Financings: If at any time, the Company issues any First Mortgage Bonds after the date hereof, the net proceeds thereof will be applied to the repayment of any outstanding Loans. In addition, the Aggregate Commitment shall be reduced by the amount of such net proceeds. II. CERTAIN CONDITIONS TO AMENDMENT The effectiveness of the Amendment will be conditioned upon, among other things, satisfaction of the following conditions precedent: 1. The Company, the Agent and each Lender shall have executed and delivered the Amendment, and the applicable parties shall have executed and delivered the Security Documentation and all such other instruments and agreements related thereto (all such documentation, including the Amendment, collectively the "Amendment Documentation") in each case in form and substance satisfactory to the Lenders. 2. All governmental and third party approvals (including the approval of the Vermont Public Service Board) necessary or advisable in connection with the execution, delivery and performance of the Amendment Documentation, including the granting of the security interest in the Collateral shall have been obtained and be in full force and effect. 3. No Default or Event of Default shall have occurred and be continuing after giving effect to the execution and delivery of the Amendment Documentation. 4. All filings and other actions required to perfect the second priority security interest in favor of the Agent on behalf of the Lenders in all the Collateral shall have been duly made or taken, and the Collateral shall be free and clear of all other liens other than those in favor of the Bondholders and other customary exceptions to be agreed upon. 5. All representations and warranties set forth in the Credit Agreement shall be true and correct in all material respects with the same effect as though made at the time of the execution and delivery by the Company of the Amendment Documentation. 6. The Lenders shall have received such legal opinions, corporate documents and other instruments as are customary for transactions of this type or as the Agent may reasonably request, in each case in form and substance satisfactory to the Agent. Such opinions shall include, without limitation, an opinion of counsel to the Company concluding that the execution and delivery of the Amendment Documentation will not conflict with, or otherwise result in a breach of any of the terms of, the First Mortgage Indenture. III REIMBURSEMENT AGREEMENT AMENDMENTS Facility Fee and Interest Rates: After giving effect to the Reimbursement Agreement Amendments, the Facility Fees and interest rates as and to the extent payable payable under each of the Reimbursement Agreements shall be increased by .25%. Collateral: The obligations of the Company to the Bank under the Reimbursement Agreements shall be secured pari passu with the Loans and other obligations of the Company to the Agent and the Lenders as described under "Collateral" in I above. The Agent will act as collateral agent for itself and the Lenders, as well as the Bank. Conditions: The effectiveness of the Reimbursement Agreement Amendments will be subject to conditions that are comparable to those listed in II above. -----END PRIVACY-ENHANCED MESSAGE-----